SIERRA PACIFIC RESOURCES, U-1, 1999-02-11

SIERRA PACIFIC RESOURCES
U-1, 1999-02-11
ELECTRIC & OTHER SERVICES COMBINED

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As filed with the Securities and Exchange Commission on February 11, 1999

File No . __-____

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------------------------

FORM U-1 APPLICATION OR DECLARATION

UNDER

THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
--------------------------------------------

Sierra Pacific Resources Nevada Power Company
6100 Neil Road 6226 West Sahara Avenue
Reno, Nevada, 89511 Las Vegas, Nevada 89146

(Name of company or companies filing this statement
and address of principal executive offices)

None

(Name of top registered holding company parent of each applicant or declarant)

Malyn K. Malquist Michael R. Niggli
Chairman of the Board, President President and Chief Operating Officer
and Chief Executive Officer Nevada Power Company
Sierra Pacific Resources 6226 West Sahara Avenue
6100 Neil Road Las Vegas, Nevada 89146
Reno, Nevada, 89511 (702)367-5000
(702) 834-3600

(Name and addresses of agents for service)
--------------------------------------------
The Commission is requested to send copies of all notices, orders and
communications in connection with this Application to:

Clifford (Mike) M. Naeve, Esq.
Skadden, Arps, Slate, Meagher & Flom LLP
1440 New York Avenue, N.W.
Washington, D.C. 20005
<PAGE>
INTRODUCTION AND REQUEST FOR COMMISSION ACTION

Pursuant to Sections 9(a)(2) and 10 of the Public Utility Holding
Company Act of 1935 (the "Act"), this Application requests that the Securities
and Exchange Commission (the "SEC" or "Commission") approve a merger between
Sierra Pacific Resources ("Sierra Pacific"), which is an exempt intrastate
holding company under the Act, and Nevada Power Company ("Nevada Power"), with
Nevada Power to become a wholly-owned subsidiary of Sierra Pacific (the
"Transaction"). Herein, Sierra Pacific and Nevada Power collectively are
referred to as the "Applicants." The Applicants also request an order under
Section 3(a)(1) of the Act declaring Sierra Pacific exempt from all provisions
of the Act except Section 9(a)(2) following consummation of the Transaction.

Nevada Power is an electric utility company under the Act. Sierra
Pacific owns all of the common stock of Sierra Pacific Power Company ("SPPC"),
which also is an electric and gas utility company under the Act. The Transaction
will not impact SPPC's structure; SPPC will continue to be a wholly-owned
subsidiary of Sierra Pacific, and will become a sister company to Nevada Power.
The Transaction is designed to create a merged company that will be able to
participate more effectively in the increasingly competitive energy marketplace.

The Transaction will be governed by the terms of an Agreement and Plan
of Merger dated as of April 29, 1998 (the "Merger Agreement"), by and among
Nevada Power, Sierra Pacific, Desert Merger Sub, Inc. ("Desert Merger Sub"), and
Lake Merger Sub, Inc. ("Lake Merger Sub"). Sierra Pacific will create two
wholly-owned, special purpose subsidiary corporations named Desert Merger Sub
and Lake Merger Sub, both to be Nevada corporations. Under the terms of the
Merger Agreement, first, Lake Merger Sub will be merged into Sierra Pacific,
with Sierra Pacific as the surviving corporation. Immediately thereafter, Nevada
Power will be merged into Desert Merger Sub. Desert Merger Sub, which will be
the surviving corporation, will then immediately change its name to Nevada Power
Company. It is through this second step that Nevada Power will become a
subsidiary of Sierra Pacific.

The Nevada Power Board of Directors ("Nevada Power Board") and the
Sierra Pacific Board of Directors ("Sierra Pacific Board") approved the
Transaction on April 29, 1998. A majority of both the Nevada Power and Sierra
Pacific common shareholders voted in favor of the Transaction in separate
meetings held on October 9, 1998. A registration statement on Form S-4, which
includes a Prospectus (the "Registration Statement") was filed with the
Commission on September 4, 1998.

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The Transaction is conditioned, among other things, upon approval by
the SEC, the Public Utilities Commission of Nevada ("Nevada PUC") and the
Federal Energy Regulatory Commission ("FERC"), and on the expiration or
termination of the applicable waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976 (as amended) (the "HSR Act"). The Applicants
expect to make the HSR filing in the first quarter of 1999.

For the Commission to approve the Transaction, Section 10 of the Act
requires the Commission to find that the Transaction will tend towards the
economical and efficient development of an integrated public-utility system and
that state laws have been complied with. The Transaction clearly satisfies these
requirements. While Section 10 also permits the Commission to disapprove an
acquisition if certain adverse circumstances would result - such as undue
concentration of control or other harm to the public interest or to the
interests of investors or consumers - these adverse circumstances are not
present here. Accordingly, the Applicants submit that the Transaction meets all
requirements of Section 10.

With respect to the exemption requested under Section 3(a)(1), the
holding company system must meet the statutory requirements of the exemption
and, in addition, the Commission must not find that the exemption would be
detrimental to the public interest or the interests of investors or consumers.
The Applicants submit that these criteria are satisfied as well.

The Applicants request expedited treatment of this application, so
that upon receipt of other regulatory approvals, Sierra Pacific and Nevada Power
will be in a position to consummate the Transaction promptly. Unless otherwise
indicated, all financial information set forth herein is for the fiscal year
ended December 31, 1997.

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ITEM 1. DESCRIPTION OF PROPOSED TRANSACTION.

A. DESCRIPTION OF THE PARTIES TO THE TRANSACTION.

1. SIERRA PACIFIC.

SPPC, the principal subsidiary of Sierra Pacific, is a public utility
incorporated in the State of Nevada. SPPC provides electric service to
approximately 287,000 retail customers in northern Nevada and northeastern
California. SPPC also sells electric power at wholesale. In the Reno/Sparks area
of Nevada, SPPC distributes natural gas at retail to approximately 101,000
customers and provides water service to about 65,000 customers. During 1997, 92%
of SPPC's revenues were from retail sales of electricity, natural gas and water
in Nevada, 6% from retail sales of electricity in California and 2% from
wholesale sales of electricity in Nevada and California . SPPC's 1997 operating
revenues, which totaled $657.5 million, were comprised of its electric business
($540 million, or 82%), natural gas business ($70.7 million, or 11%) and water
business ($46.5 million, or 7%). As of December 31, 1997, SPPC's net utility
plant in service was $ 1.4 billion. A map of SPPC's electric/gas service area is
attached as Exhibit E-1.

During 1997, the peak electric demand experienced by SPPC was 1342
megawatts ("MW"). SPPC served this demand, plus a reserve margin, with a
combination of the following: (i) 1049 MW of power generated by plants owned by
SPPC, (ii) 334 MW of power purchased pursuant to long term contracts, and (iii)
additional firm and short-term power purchases. SPPC's fuel requirements for
electric generation were provided by natural gas (62%), coal (37%) and oil (1%).

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1 Sierra Pacific Resources, Holding Co. Act Release No. 24566 (Jan. 28,
------------------------
1988), aff'd, Environmental Action, Inc. v. SEC, 895 F.2d 1255 (D.C. Cir.
1990). ----- ---------------------------------

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As of December 31, 1997, SPPC's electric transmission facilities
consisted of approximately 3,900 overhead pole line miles and 80 substations.
Its electric distribution facilities consisted of approximately 9,200 overhead
pole line miles, 4,500 underground cable miles and 176 substations.

SPPC's natural gas business consists of providing local distribution
service in the Reno/Sparks area that accounted for $70.7 million in 1997
operating revenues; 11% of total SPPC operating revenues. SPPC has contracted
for firm winter-only and annual natural gas supplies with Canadian and domestic
suppliers to meet the firm gas requirements of its local distribution and
electric operations. The contracts total 125,000 decatherms per day through
March 1998; 72,000 decatherms per day for April through October 1998 and 75,000
decatherms per day for the remainder of 1998. SPPC's firm natural gas supply is
supplemented with natural gas storage services and supplies from a Northwest
Pipeline Company facility located at Jackson Prairie in southern Washington and
a liquid natural gas storage facility. For 1997, SPPC's total local gas
distribution supply requirements were 12.4 million decatherms and its electric
generating fuel requirements were 32.0 million decatherms. As of December 31,
1997, SPPC owned and operated 1,219 miles of three-inch equivalent natural gas
distribution lines.

SPPC is subject to regulation by the Nevada PUC and the California
Public Utilities Commission ("California PUC") with respect to its rates for
retail sales of electricity as well as terms of service, issuance of certain
securities, siting of and necessity for generation and certain transmission
facilities, accounting and other matters. In addition, SPPC is subject to
regulation by FERC under the Federal Power Act with respect to rates for the
sale of electricity for resale, the terms and conditions for providing
interstate electric transmission service, and other matters. SPPC also is
subject to applicable federal and state environmental regulations.

Sierra Pacific is engaged in non-utility businesses, as well as
certain other utility businesses that are not jurisdictional under the Act,
through the following subsidiaries:

1. Tuscarora Gas Pipeline Company was formed as a wholly-owned
subsidiary in 1993 for the purpose of entering into a partnership (the Tuscarora
Gas Transmission Company or, "TGTC") with a subsidiary of TransCanada to
develop, construct and operate a natural gas pipeline to serve an expanding gas
market in Reno, northern Nevada and northeastern California. Sierra Pacific has

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an investment of approximately $15.5 million in this subsidiary. In 1995, TGTC
completed construction and began service of its 229-mile pipeline extending from
Malin, Oregon to Reno, Nevada. At Malin, Oregon, TGTC interconnects with Pacific
Gas Transmission Company ("PGT"), a major interstate natural gas pipeline
extending from Oregon to the U.S./Canadian border. The PGT system provides TGTC
customers access to natural gas reserves in the Western Canadian Sedimentary
basin, one of the largest natural gas reserve basins in North America. As an
interstate pipeline, TGTC provides only transportation service. During 1997,
SPPC and Sierra Pacific were the two largest customers of TGTC, contributing
92.2% and 6.3 % of TGTC's revenues, respectively. Malin, Oregon began taking
service from TGTC during the later part of 1996. The Sierra Army Depot at
Herlong, California began taking service from TGTC during the later part of
1997.

2. Sierra Energy Company d/b/a e-three ("e-three") is an
unregulated, wholly-owned subsidiary that provides energy-related products and
services both inside and outside SPPC's service territory.

3. Lands of Sierra, Inc. ("LOS") was organized in 1964 to develop
and manage SPPC non-utility property in Nevada and California. In recent years,
Sierra Pacific has focused on selling the LOS properties and the properties
remaining include only vacant land in Nevada and land leases in the Lake Tahoe
region.

4. Sierra Pacific Energy Company ("SPEC"), which is developing a
customer information system for the energy industry. SPEC also is engaged in
providing certain products and services in Nevada through a partnership with
Enable, which is a partnership consisting of KN Energy and PacifiCorp
subsidiaries.

The common stock of Sierra Pacific, par value $1 per share ("Sierra
Pacific Common Stock"), is listed on the New York Stock Exchange (the "NYSE"),
under the symbol SRP. As of the close of business on December 31, 1998, there
were 31,009,364 shares of Sierra Pacific Common Stock issued and outstanding.

For the year ended December 31, 1997, Sierra Pacific's operating
revenues on a consolidated basis were approximately $663 million, of which $6
million are attributable to non-utility activities. Consolidated assets of
Sierra Pacific and its subsidiaries at December 31, 1997, were approximately

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$1.9 billion, of which approximately $1.4 billion consisted of net utility plant
and equipment.

Sierra Pacific's principal executive office is located at 6100 Neil
Road, Reno, Nevada, 89511. At December 31, 1997, Sierra Pacific and its
subsidiaries employed 1,478 employees, of which 1,473 were employed by SPPC.

More detailed information concerning Sierra Pacific and its
subsidiaries is contained in Sierra Pacific's and SPPC's Annual Reports on Form
10-K for the year ended December 31, 1997, which are incorporated herein by
reference as Exhibits G-1 and G-3, respectively.

2. NEVADA POWER.

Nevada Power has total generating capacity of 2,714 MW, which includes
(i) 1,964 MW of power generated by plants owned by Nevada Power, (ii) 235 MW of
Hoover Dam power purchased pursuant to a contract with the State of Nevada ,
(iii) 210 MW of power purchased pursuant to a contract with Nevada Sun-Peak
Limited Partnership, an independent power producer, and (iv) 305 MW of power
purchased pursuant to contracts with four qualifying facilities. In addition,
Nevada Power has agreements with other suppliers to purchase 1,130 MW of firm
capacity and associated energy. During 1997, the peak demand experienced by
Nevada Power was 3,469 MW on August 7, 1997. Nevada Power served this demand,
plus a reserve margin, with a combination of its 2,714 MW of generating capacity
and additional firm and short-term power purchases. To obtain additional firm
capacity and associated energy to meet peak needs, Nevada Power utilizes a
competitive bidding process and spot market purchases. During 1997, 67% of the
energy generated by Nevada Power's plants came from coal-fired stations and 33%
from natural gas-fired stations.

As of December 31, 1997, Nevada Power owned approximately 1,575 miles
of electric transmission facilities (a portion of that under shared ownership),
108 transmission and distribution substations, and a distribution system

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consisting of approximately 3,162 overhead pole line miles and 8,957 underground
cable miles.

Nevada Power is subject to regulation by the Nevada PUC with respect
to its rates for retail sales of electricity as well as terms of service,
issuance of certain securities, siting of and necessity for generation and
certain transmission facilities, and accounting and other matters. In addition,
Nevada Power is subject to regulation by FERC under the Federal Power Act with
respect to rates for the sale of electricity for resale, the terms and
conditions for providing interstate electric transmission service, and other
matters. Nevada Power is also subject to applicable federal and state
environmental regulations.

The common stock of Nevada Power, par value $1 per share ("Nevada
Power Common Stock"), is listed on the NYSE and the Pacific Exchange, Inc.,
under the symbol NVP. As of the close of business on December 31, 1998, there
were 51,265,117 shares of Nevada Power Common Stock issued and outstanding.

For the year ended December 31, 1997, Nevada Power's utility operating
revenues on a consolidated basis were approximately $799 million. Consolidated
assets of Nevada Power and its subsidiaries at December 31, 1997, were
approximately $2.3 billion, of which approximately $1.7 billion consisted of net
electric plant and equipment. Nevada Power does not have any material revenue
generating subsidiaries.

Nevada Power's principal executive office is located at 6226 West
Sahara Avenue, Las Vegas, Nevada, 89146. At December 31, 1997, Nevada Power
employed approximately 1,909 employees.

More detailed information concerning Nevada Power is contained in
Nevada Power's Annual Report on Form 10-K for the year ended December 31, 1997,
which is incorporated herein by reference as Exhibit G-5.

3. DESERT MERGER SUB AND LAKE MERGER SUB.

Sierra Pacific created Desert Merger Sub and Lake Merger Sub, both
Nevada corporations, solely for the purpose of merging with Nevada Power and
Sierra Pacific, respectively. Neither Desert Merger Sub nor Lake Merger Sub is

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engaged in any business operations. The mailing address for Desert Merger Sub
and Lake Merger Sub is the same as that for Sierra Pacific.

B. DESCRIPTION OF THE TRANSACTION.

1. REASONS FOR THE TRANSACTION.

Nevada Power and Sierra Pacific view the Transaction as a natural
outgrowth of utility deregulation and restructuring that is reshaping the
electric industry in Nevada, California and throughout the nation. Pursuant to a
Nevada law (Assembly Bill 366, codified at Nev. Rev. Stat. ss.ss. 704.961-990
(1997)), electric competition for retail sales service must commence in the
state no later than December 31, 1999. However, the Nevada PUC has discretion to
extend the commencement date. The Transaction joins two companies of similar
market capitalization, with a common vision of the future of the utility and
energy industries and with complementary operations that almost exclusively are
in one state. The Transaction is expected to provide substantial strategic and
financial benefits to the stockholders of the two companies, as well as to their
employees and customers and the communities which they serve. The Nevada Power
Board and the Sierra Pacific Board believe that such benefits include:

o Support for Utility Deregulation. The Transaction coincides with Nevada
electric utility deregulation and ongoing California electric utility
deregulation and is intended to establish a combined company that, by
providing customers multiple energy products and services and lower costs
than the companies could achieve individually, will have the ability to
compete more effectively in unregulated markets and serve customers more
cost-effectively in regulated markets. Nevada Power and SPPC also propose
selling all of their generating plants. Under the divestiture proposal and
subject to ongoing state resource planning requirements, amounts raised by
the sale will be reinvested primarily in new transmission and distribution
facilities. Nevada Power and SPPC believe that divestiture of their
generating capacity will facilitate the move to a competitive market for
electricity in Nevada and elsewhere. The divestiture proposal is contingent
upon consummation of the Transaction and receipt of necessary
authorizations. Through Nevada Power and SPPC, the combined company will
offer regulated retail electric distribution service throughout most of
Nevada and a small portion of northern California and offer regulated gas
distribution and water service in the Reno and Sparks areas of northern
Nevada. Unregulated subsidiaries of Sierra Pacific will engage in natural

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gas and electricity marketing and offer energy related products and
services.

o Competitive and Strategic Position. The combination of the companies'
complementary expertise and vision, including Nevada Power's substantially
larger and more diverse electric customer base and its customer expertise
and Sierra Pacific's customer and marketing expertise in both electricity
and natural gas markets, provides the combined company with the size and
scope to be an effective competitor in the emerging and increasingly
competitive markets for transporting and distributing energy and energy
services. The Transaction will create a company with the ability to develop
and market competitive new products and services and provide integrated
energy solutions for wholesale and retail customers.

o Ability to Better Manage Growth. Both Nevada Power and SPPC have
experienced high rates of service territory growth. Five-year average
increases in retail electric kWh sales and customers for the companies,
separately and as combined, compared to industry averages are as follows:

<TABLE>
<CAPTION>
5-Year Average 5-Year Average
Retail Electric kWh Increase in
Company Sales Increases Customers
------- ------------------- --------------

<S> <C> <C>
Nevada Power.............. 8% 7%

SPPC...................... 5% 3%

Combined Company.......... 7% 5%

Industry Average.......... 2% 1%
</TABLE>

The Nevada Power Board and the Sierra Pacific Board believe that the
combined company will be in a better position to finance and manage the
construction and operational changes required to meet the increasing needs
of customers in Southern and Northern Nevada while also maintaining
stronger earnings than either company could standing alone. The Transaction
is expected to have a positive effect on cash flow of the combined
companies.

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o Expanded Management Resources and Employment Opportunities. The combined
company will be able to draw upon a larger and more diverse pool of
management for leadership in an increasingly competitive environment. As a
company more able to effectively respond to competitive pressures, the
combined company will offer better prospects for employees and be better
able to retain and attract the most qualified employees. Employees will
benefit from a larger and stronger company with job opportunities in
additional locations.

o Community Development. The combined company will continue to play a leading
role in the economic development of the communities served by Nevada Power
and SPPC and will continue the commitment to philanthropic and volunteer
programs currently maintained by the two companies and their subsidiaries.
These communities also will benefit from increased competition and lower
prices for regulated and deregulated natural gas and electricity and energy
related products and services.

o Potential Cost Savings and Cost Avoidances Resulting from the Transaction.
Estimated potential savings and cost avoidances expected to be achieved by
the two companies after the Transaction has been limited to quantifiable
amounts, as determined by the managements of Nevada Power and Sierra
Pacific. Recognition has been given to those costs to be incurred in
achieving these potential savings and cost avoidances and to the time
required to implement plans designed to integrate operations. These
estimated savings and cost avoidances are attributable to the Transaction
and do not include other types of savings and cost avoidances that might be
achieved without a combination of the companies. In addition, Sierra
Pacific will continue efforts already underway by Nevada Power and SPPC to
increase productivity and reduce costs by redesigning and reengineering key
business processes. Operating synergies from the Transaction are estimated
to generate total cost savings and cost avoidances, net of $125 million
estimated costs to achieve such savings and avoidances, of $322 million
over a ten-year period. In addition, the goodwill recorded as a result of
the Transaction will be amortized over a forty-year period and also will
represent a cost to achieve such savings and avoidances. The final
accounting treatment of the cost savings and cost avoidances and costs of
attaining them will depend upon the regulatory treatment accorded by the
Nevada PUC.

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The major components of the anticipated cost savings and cost avoidances
identified by the managements of Nevada Power and Sierra Pacific are set
forth below.

o Integration of corporate functions. The combined company will have the
ability to eliminate redundant functions in a variety of areas,
including accounting and finance, human resources, information
services, external relations, legal and executive administration. The
staffing levels for these functions are relatively fixed and do not
vary directly with changes in the number of employees or customers.

o Integration of corporate programs. The combined company will be able
to integrate various corporate and administrative functions, thereby
reducing certain non-labor costs in the areas of insurance,
advertising, professional services, benefits plan administration,
credit facilities, association dues, postage, research and development
and shareholder services. In addition, future expenditures in the area
of information systems that would be made by each company on a
stand-alone basis will be reduced for the combined company. Additional
expenditures will be reduced through the more efficient management of
investment in other technology areas, including personal computers,
other hardware and related software, and data center requirements.

o Integration of competitive retail services. Following the commencement
of retail electric competition in Nevada, retail electric service and
metering service will be offered on a competitive basis. Currently,
Nevada Power and SPPC provide retail electric service and metering
service on a separate, regulated basis. However, as a result of the
electric restructuring, Nevada Power and SPPC will provide these
services on a competitive basis through a jointly-owned retail service
company and a metering company. The Applicants intend to consolidate
as many other business practices as make economic sense.

o Integration of customer support functions. The combined company will
be able to integrate related customer support functions in the areas
of customer service, marketing and sales, and other support services,

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such as purchasing and materials management. The staffing levels in
these functions also do not increase or decrease linearly with the
number of customers.

o Streamlining of inventories and purchasing economics. The combined
company will be able to centralize some purchasing and inventory
functions. Inventory may be shared across locations. Purchasing
leverage of the combined company is expected to lead to materials and
services volume discounts.

Most of the estimated cost savings and cost avoidances as described above
are expected to be achieved through personnel reductions involving the
elimination of approximately 250 duplicative positions. Nevada Power and
Sierra Pacific jointly will develop an integration management plan, which
will examine the manner in which to best organize and manage the businesses
of Nevada Power and Sierra Pacific following consummation of the
Transaction and to identify duplicative positions in corporate and
administrative functions. Both companies are committed to achieving cost
savings and avoidances resulting from personnel reductions through
attrition, strictly controlled hiring, reassignment, retraining and
voluntary separation programs.

2. MERGER AGREEMENT.

The Merger Agreement calls for a merger of equals between the two
companies - Nevada Power and Sierra Pacific. The Merger Agreement provides for a
holding company structure in which Sierra Pacific will be the surviving parent
company, and Nevada Power and SPPC will be the operating utility subsidiaries.
Sierra Pacific also will continue to own the non-utility subsidiaries that it
owns today.

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In the first step, Lake Merger Sub will merge with and into Sierra
Pacific, with Sierra Pacific continuing as the surviving corporation. This step
is necessary because, as discussed below, each share of pre-merger Sierra
Pacific common stock may be exchanged for $37.55 in cash or 1.44 shares of
Sierra Pacific common stock. The exchange of pre-merger stock for cash or stock
occurs as a result and at the time of this first merger.

The second step of the process commences immediately after this first
step. Nevada Power will merge with and into Desert Merger Sub. Desert Merger
Sub, which will be the surviving corporation, will then immediately change its
name to Nevada Power Company. It is through this second step that Nevada Power
will become a subsidiary of Sierra Pacific.

Under the Merger Agreement, each share of Sierra Pacific and Nevada
Power Common Stock will be converted into the right to receive cash and/or
Sierra Pacific Common Stock. Each owner of Sierra Pacific Common Stock prior to
the first merger will be entitled to receive either 1.44 shares of Sierra
Pacific Common Stock or $37.55 in cash in exchange for each share of Sierra
Pacific Common Stock that it owns. Each owner of Nevada Power Common Stock prior
to the second merger will be entitled to receive either 1 share of Sierra
Pacific Common Stock or $26.00 in cash in exchange for each share of Nevada
Power stock that it owns. The cash consideration for Sierra Pacific and Nevada
Power stock represents a 5% premium per share of Sierra Pacific Common Stock or
Nevada Power Common Stock, respectively based on the 10-day average share price
of each company's stock prior to the Boards' approval of the Merger Agreement on
April 29, 1998.

The total amount of cash to be paid to shareholders of pre-merger
Sierra Pacific Common Stock in the first merger is $151.6 million, and the total
amount to be paid to shareholders of Nevada Power Common Stock in the second
merger is $304.6 million. The Merger Agreement provides for contingencies should
shareholders elect to convert more or less than this amount of their shares to
cash. The Merger Agreement also provides for special treatment of shareholders
of less than 100 shares. Sierra Pacific will finance the approximately $460
million necessary to fund the cash consideration provided for under the Merger
Agreement. The exact sources and precise methods of financing this amount have
not yet been determined.

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The Merger Agreement provides that all outstanding shares of Nevada
Power preferred stock will be redeemed or otherwise retired prior to the
consummation of the Transaction. At any time upon 30 days notice to the holders
of the Nevada Power preferred stock, such stock is redeemable at a price of
$21.00 per share for the 5.20% and 5.40% series and at $20.25 per share for the
4.70% series. Nevada Power has not determined precisely when or how it will
retire the Nevada Power preferred stock.

The Transaction is subject to certain closing conditions, including
governmental authorizations, consents, orders or approvals. The requisite
shareholder approvals have been obtained.

The Merger Agreement may be terminated under certain circumstances,
including: by mutual written consent of Sierra Pacific and Nevada Power; by
either party if the Transaction is not consummated by October 29, 1999 (which
date will be extended to April 29, 2000 in certain circumstances); by either
party if any state or federal law or court order prohibits consummation of the
Transaction; by a non-breaching party if there occurs a material breach by the
other party of the Merger Agreement which is not cured within 20 days after
notice; or by either party, in certain circumstances, as a result of a more
favorable third-party tender offer or business combination proposal with respect
to such party. The Merger Agreement requires that termination fees be paid in
certain circumstances, including if there is a willful breach of the Merger
Agreement or if, in certain circumstances, a business combination with a third
party is consummated within two and one-half years of the termination of the
Merger Agreement. The aggregate termination fees under these provisions is $52.5
million.

In connection with the Merger Agreement, Sierra Pacific and Nevada
Power entered into several related agreements, including employment agreements,
severance arrangements and confidentiality agreements. These related agreements
are described further in the Registration Statement (Ex. C-1).

3. BACKGROUND AND NEGOTIATIONS LEADING TO THE TRANSACTION.

In recent years Nevada Power and Sierra Pacific have carefully
followed developments in energy regulatory policies at the federal level and in
Nevada and California that have substantially increased competition in the
markets for wholesale and retail electricity. Both companies recognized that
significant changes in the utility industry would result from these policy

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developments. The companies believe that industry restructuring and economic
forces are likely to exert tremendous pressure on small and medium-sized
electric utilities, making it difficult for them to compete effectively with
larger utilities. As such, the two companies had exploratory discussions from
time to time in recent years regarding a potential business combination between
Sierra Pacific and Nevada Power but no further steps were taken.

During February 1998, Mr. Michael Niggli, President and Chief
Operating Officer of Nevada Power, and Mr. Malyn Malquist, President, Chairman
of the Board and Chief Executive Officer of Sierra Pacific, talked about their
shared visions for Nevada Power and Sierra Pacific, and senior management of
each company began to discuss the potential benefits of a possible business
combination. The Nevada Power Board and the Sierra Pacific Board were advised of
these discussions in February and March 1998.

On March 5 and 6, 1998, a joint meeting was held in San Francisco
between Nevada Power and Sierra Pacific along with Nevada Power's financial
advisor PaineWebber Incorporated ("PaineWebber") and Sierra Pacific's financial
advisor SG Barr Devlin to discuss a possible business combination. As a result,
on March 10, 1998, Sierra Pacific and Nevada Power entered into a
confidentiality agreement pursuant to which they agreed to exchange non-public
information. Following these meetings, the companies commenced extensive due
diligence and exchanged information.

On March 12, 1998, at a meeting of the Nevada Power Board, Nevada
Power's senior management and representatives of PaineWebber, Nevada Power's
financial advisor, made a detailed presentation to the Nevada Power Board with
regard to a potential "merger of equals" business combination with Sierra
Pacific. At the conclusion of the meeting, the Nevada Power Board gave
management authorization to continue to explore a possible combination with
Sierra Pacific.

On March 13, 1998, at a meeting of the Sierra Pacific Board, Sierra
Pacific's senior management and representatives of SG Barr Devlin, Sierra
Pacific's financial advisor, briefed the Sierra Board with regard to a potential
"merger of equals" business combination with Nevada Power. The Sierra Pacific
Board authorized Mr. Malquist and Mr. Oldham, Vice President, Transmission
Services Group and Strategic Development of Sierra Pacific, to continue
discussions with Nevada Power regarding such a business combination.

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Throughout the remainder of March and April 1998, representatives of
Sierra Pacific and Nevada Power held numerous discussions which focused
primarily on the issues of valuation, dividend policy, management and
headquarters locations. On March 30, 1998, Merrill Lynch, Pierce, Fenner & Smith
Incorporated ("Merrill Lynch") was retained to provide additional financial
advice and guidance to management and the Sierra Pacific Board. During April
1998, the Nevada Power Board and the Sierra Pacific Board were briefed
separately on the progress of negotiations, including reviews of the steps that
had been taken regarding due diligence and transaction structure, as well as
proposals regarding corporate names and headquarters locations, board
representation and senior management composition. The presentations described
potential strategic benefits of the transaction, the status of negotiations on,
and key terms and conditions of, the proposed Merger Agreement and the
regulatory plan for the transaction.

By the last week of April 1998, Nevada Power and Sierra Pacific had
agreed on a merger of equals transaction consisting of a cash election merger
where holders of Nevada Power Common Stock could elect to receive for each of
their shares either $26.00 in cash or one share of Sierra Pacific Common Stock
and holders of Sierra Pacific Common Stock could elect to receive for each of
their shares either $37.55 in cash or 1.44 shares of Sierra Pacific Common
Stock. The companies further agreed that following the Transaction, former
holders of Nevada Power Common Stock would own approximately 50.2% of the
outstanding Sierra Pacific Common Stock, and former holders of Sierra Pacific
Common Stock would own approximately 49.8% of the outstanding Sierra Pacific
Common Stock.

On April 29, 1998, the Sierra Pacific Board and the Nevada Power Board
each approved the Merger Agreement. Following the meetings of their respective
Boards, Sierra Pacific and Nevada Power executed the Merger Agreement on April
29, 1998 and publicly announced the proposed Transaction on April 30, 1998.

For a more detailed description of the background of the Transaction,
see pages 38-43 of the Registration Statement (Ex. C-1).

C. MANAGEMENT AND OPERATIONS OF THE APPLICANTS FOLLOWING THE
TRANSACTION.

The Merger Agreement provides that the post-merger Sierra Pacific
Board of Directors will consist of 14 members, 7 to be selected by Sierra

17
<PAGE>
Pacific and 7 to be selected by Nevada Power. Mr. Niggli (currently, President
and Chief Operating Officer of Nevada Power Company), and Mr. Malquist
(currently, Chairman, President and Chief Executive Officer of Sierra Pacific
and SPPC) will be members of the Sierra Pacific Board of Directors after the
Transaction is consummated. Subject to affiliate rules promulgated by regulatory
agencies having jurisdiction over the matter, Mr. Niggli will become Chairman
and Chief Executive Officer of Sierra Pacific and Chairman of each of its
subsidiaries and Mr. Malquist will become President and Chief Operating Officer
of Sierra Pacific and President and Chief Executive Officer of the surviving
Nevada Power and SPPC.

The Merger Agreement provides that post-merger, the corporate
headquarters of Sierra Pacific and the principal offices of the natural gas and
water business units will be located in Reno, Nevada. The headquarters of SPPC
and the surviving Nevada Power will be located in Las Vegas, Nevada. Nevada
Power and SPPC will continue to operate as the utility subsidiaries of Sierra
Pacific.

ITEM 2. FEES, COMMISSIONS AND EXPENSES.

The fees, commissions and expenses to be paid or incurred, directly or
indirectly, by Sierra Pacific and Nevada Power, in connection with the
Transaction, including registration of securities of Sierra Pacific under the
Securities Act of 1933, and other related matters, are estimated as follows:

Commission filing fee for Sierra Pacific
Registration Statement on Form S-4......................................$712,020
HSR filing fee...........................................................$45,000
Accountants' fees..............................................................*
Shareholder communication (including prospectus printing
and distribution)............................................................*
NYSE listing fee...............................................................*
Exchanging, printing, and engraving of stock
certificates.................................................................*
Investment bankers' fees and expenses................................$15,400,000
Legal fees and expenses (including regulatory and antitrust)..........$6,000,000
Miscellaneous (including consultants)..........................................*
TOTAL (estimated) ..............................................$26,000,000

(*) To be filed by amendment.

18
<PAGE>
ITEM 3. APPLICABLE STATUTORY PROVISIONS.

A. STATEMENT OF APPLICABLE PROVISIONS.

Sections 9(a)(2), 10, and 3(a)(1) of the Act are directly or
indirectly applicable to the proposed Transaction.

Under Section 9(a)(2), it is unlawful, without approval of the
Commission, under the standards of Section 10, for any person to acquire,
directly or indirectly, the securities of a public utility company, if that
person will, by virtue of the acquisition, become an affiliate of that public
utility and any other public utility or holding company. The term "affiliate"
for this purpose means any person that directly or indirectly owns, controls, or
holds with power to vote, five percent or more of the outstanding voting
securities of the specified company.

Pursuant to the Transaction, Sierra Pacific will acquire securities of
Nevada Power, a public utility. After the Transaction, Sierra Pacific will be
affiliated with two public utilities - SPPC and Nevada Power. Accordingly, the
Transaction requires Commission approval under the standards of Section 10.

Following the Transaction, Sierra Pacific believes, for reasons
explained below, that it will qualify for the intrastate exemption under Section
3(a)(1) of the Act, and requests an order granting such exemption. Under this
section, the Commission must exempt, by rule or order, any holding company if
that holding company, and each material public utility subsidiary company from
which the holding company derives any material part of its income, are
predominantly intrastate in character, and carry on their business in the state
in which they are organized, unless and except insofar as the Commission finds
the exemption detrimental to the public interest or the interest of investors or
consumers.

B. THE STANDARDS OF SECTION 10.

The statutory standards to be considered by the Commission in
evaluating the Transaction are set forth in Sections 10(b), 10(c) and 10(f) of
the Act.

19
<PAGE>
1. SECTION 10(B).

Under Section 10(b) of the Act, the Commission must approve the
Transaction unless the Commission finds that:

(1) such acquisition will tend towards interlocking relations or the
concentration of control of public-utility companies, of a kind or to an
extent detrimental to the public interest or the interest of investors or
consumers;

(2) in case of the acquisition of securities or utility assets, the
consideration, including all fees, commissions and other remuneration, to
whomsoever paid, to be given, directly or indirectly, in connection with
the acquisition is not reasonable or does not bear a fair relation to the
sums invested in or the earning capacity of the utility assets to be
acquired or the utility assets underlying the securities to be acquired; or

(3) such acquisition will unduly complicate the capital structure of
the holding-company system of the applicant or will be detrimental to the
public interest or the interest of investors or consumers or the proper
functioning of such holding company system.

a. DETRIMENTAL "INTERLOCKING RELATIONS" OR "CONCENTRATION OF
CONTROL."

The Transaction will not result in detrimental interlocking relations
or concentration of control. There currently are no common directors of Sierra
Pacific and Nevada Power, but following consummation of the Transaction there
may be common directors and officers of Sierra Pacific, SPPC and Nevada Power.
Such interlocking relationships, however, would serve to integrate the merging
companies, and are characteristic of virtually every merger transaction subject
to Section 9(a)(2). Thus, any interlocking relations which do occur will be of
the kind generally approved of by the Commission and will not be detrimental to
interests of consumers, investors or the public.

The Transaction also will not result in a detrimental concentration of
control. The expected increase in size resulting from the Transaction will not
make the merged company a large company. Instead, the Transaction will take two

20
<PAGE>
relatively small utility companies and combine them into one mid-sized company.
The merged company still will be much smaller than almost all of its neighboring
utilities and holding company systems such as Southern California Edison,
Pacific Gas & Electric, PacifiCorp and Bonneville Power Administration ("BPA"),
which are among the largest utilities in the country.2 As a consequence, the
merged company will not be able to dominate the region. Following the
Transaction, Sierra Pacific will have total utility assets of $3.1 billion,
total utility revenues of $1.4 billion, and will serve approximately 805,000
electric customers and 101,000 natural gas customers. However, as discussed
above, the Applicants intend to divest their electric generation assets. The
utility activities of Sierra Pacific following the Transaction will be confined
almost exclusively to Nevada. The Commission has approved a number of
transactions which resulted in holding companies of a much larger size.3

Section 10(b)(1) also requires the Commission to consider possible
anticompetitive effects of a proposed merger. In this case, the Commission has
concurrent jurisdiction with the Department of Justice (the "DOJ"), Federal
Trade Commission (the "FTC"), FERC and the Nevada PUC to consider the
competitive effects of the Transaction. The Applicants will file Notification
and Report Forms with the DOJ and the FTC, as required by the HSR Act, which the
Applicants expect to file in the first quarter of 1999, will contain a
description of the Transaction's effects on competition. Consummation of the
Transaction is conditioned on the expiration or termination of the applicable
waiting period under the HSR Act. In addition, the Applicants have made filings
with the Nevada PUC and FERC, the agencies having immediate jurisdiction over
Nevada Power's and SPPC's utility operations. These filings, which are attached

- ---------------

2 As of December 31, 1997, Pacific Gas & Electric Company had $25.1 billion
in utility assets and generated $9.5 billion in operating revenues for
1997. PacifiCorp had $9.1 billion in utility assets as of December 31, 1997
and $3.7 billion in operating revenues for 1997.

3 See, e.g., TUC Holding Co., File No. 70-8953, Rel. No. 35-26749 (issued
August 1, 1997). TUC Holding has utility assets of approximately $19.6
billion, operating utility revenues of approximately $6.9 billion and
approx imately 2.7 million utility customers. See also Entergy Corp., 51
S.E.C. 869 (combined utility assets after Gulf States acquisition of $21
billion).

21
<PAGE>
as Exhibits D-1 and D-3, contain detailed explanations of why the Transaction
will not have any adverse competitive effect. FERC will evaluate the
Transaction's competitive effects and will approve the Transaction only upon
finding that it is in the public interest and will not adversely affect
competition. Following its evaluation of the competitive effects of the
Transaction, the Nevada PUC issued an order dated January 4, 1999, approving the
Transaction, subject to certain conditions. A copy of the Nevada PUC order is
attached as Exhibit D-2.

The testimony of Peter Fox-Penner, which is Exhibit SPNP-17 to the
FERC application attached as Exhibit D-3 hereto, explains why the Transaction
will not have anticompetitive effects. The Applicants are located in the Western
System Coordinating Council ("WSCC"). Due to the structure of the WSCC market,
the Transaction cannot cause a reduction in competition. First, the Applicants
are relatively small utilities in the WSCC. Together, the Applicants own a total
of approximately 3,800 MW of generation capacity, representing slightly more
than one-tenth of the WSCC surplus capacity. The amount of the Applicants'
generation capacity pales even further when compared to the approximately
155,000 MW of generation resources located in the WSCC. All of the Applicants'
generating capacity is needed to serve their native load customers. Because the
Applicants do not own enough generating capacity to meet their native load
obligations, they are net power purchasers by a wide margin in both short term
and long term power markets. Not only are the Applicants small when compared to
the WSCC as a region, but they are also small compared to the control areas with
which they are interconnected, such as BPA, Pacific Gas & Electric, Southern
California Edison and PacifiCorp. Second, Sierra Pacific does not make sales
into Nevada Power's control area, and visa versa. Because the Applicants do not
compete with each other in their respective control areas, the proposed merger
does not cause the loss of a competitor or any increase in market power in those
control areas. Third, with one insignificant exception, Nevada Power and SPPC
are interconnected only through different utility systems. SPPC's primary
interconnections are with systems to the north and northwest of Nevada, whereas
Nevada Power's primary interconnections are to the south and southwest of
Nevada. The only system that has significant interconnections with both Nevada
Power and SPPC is the PacifiCorp-East system to the east. As a consequence, the
merger would cause no concentration of market power in the bulk power markets of
the systems directly connected to the Applicants. Fourth, because the Applicants
are such small players in the regional bulk power market as a whole, their
combination cannot cause any meaningful or measurable increase in market share
in regional markets outside of their own service territories. Hence, the

22
<PAGE>
Commission can conclude that the Transaction will have no adverse competitive
effects. Indeed, for the reasons stated below, the Commission may conclude that
the Transaction will facilitate even greater competition in electric wholesale
and retail markets.

Under a new Nevada law (Assembly Bill 366, codified at Nev. Rev. Stat.
ss.ss. 704.961-990 (1997)), Nevada Power's and SPPC's retail electric service
territories in Nevada will be opened to retail competition as early as December
31, 1999. FERC already has introduced competition into wholesale electric
markets through its many orders authorizing market-based rates for wholesale
power sales and a series of orders mandating non-discriminatory access to
electric transmission facilities. The Transaction will facilitate both state and
federal efforts to increase competition in electric markets because, as part of
the merger, the Applicants have committed to the Nevada PUC to divest their
generation assets and, subject to state resource planning approvals, invest the
proceeds in the expansion of their transmission and distribution capacity. This
expansion is important because there is limited import capability into the
Nevada Power and SPPC service territories. Increasing the import capability will
expand the number of suppliers that can compete to serve customers in the Nevada
electricity market. The goal of generation divestiture is to balance market
power mitigation while retaining the value of the underlying assets. The
divestiture proposal is contingent upon consummation of the Transaction and
receipt of necessary authorizations. To permit an orderly sale process, Nevada
Power and SPPC have committed to divest their generation by the later of
December 31, 1999 or the commencement of retail competition in Nevada. Another
pro-competitive benefit accompanying the merger is the Applicants' commitment to
either join a regional independent system operator ("ISO") or form an
independent "Transco" that would operate the Applicants' transmission
facilities, within no more than three years.

The additional benefits accompanying the Transaction are outlined
below in Items 1(B)(1) and 3(B)(2) of this Application, and are benefits which
the Commission has weighed against any concerns about concentration of control
it has had in other transactions. See American Electric Power Co., 46 S.E.C.
1299 (1978).

For all of these reasons, the Applicants believe that the Transaction
will not result in a concentration of control which will be detrimental to the
public interest, but will offer the potential to facilitate an actual increase
in competition in regional electricity markets.

23
<PAGE>
b. FAIRNESS OF CONSIDERATION.

Section 10(b)(2), as applied to the Transaction, provides that the
Commission shall approve the Transaction unless it finds that the consideration
paid by Sierra Pacific to the shareholders of Nevada Power is not reasonable or
does not bear a fair relation to the earning capacity of the utility assets
underlying the Nevada Power shares. In its determination as to whether or not
consideration for an acquisition meets the fair and reasonable test of Section
10(b)(2), the Commission has considered whether the price was decided as the
result of arm's-length negotiations4 and whether each party's Board of Directors
has approved the purchase price.5 The Commission also considers the opinions of
investment bankers6 and the earnings, dividends, and book and market value of
the shares of the company to be acquired.7

Pursuant to the Merger Agreement, each owner of pre-merger Sierra
Pacific Common Stock will be entitled to receive either 1.44 shares of
post-merger Sierra Pacific Common Stock or $37.55 in cash in exchange for each
share of premerger Sierra Pacific Common Stock that it owns ("Sierra Pacific
Merger Consideration"). Each owner of Nevada Power Common Stock will be entitled
to receive either 1 share of post-merger Sierra Pacific Common Stock or $26.00
in cash in exchange for each share of Nevada Power stock that it owns ("Nevada
Power Merger Consideration"). The cash consideration for Sierra Pacific and
Nevada Power stock represents a 5% premium per share of Sierra Pacific Common
Stock or Nevada Power Common Stock, respectively based on the 10-day average
share price of each company's stock prior to the Boards' approval of the Merger
Agreement on April 29, 1998. Pursuant to the Merger Agreement, approximately
$151.6 million in cash and approximately 38,740,334 shares of the Sierra Pacific
Common Stock will constitute the Sierra Pacific Merger Consideration, and
approximately $304.6 million in cash and approximately 39,051,502 shares of
Sierra Pacific Common Stock will constitute the Nevada Power Merger
Consideration.

- ---------------

4 American National Gas Co., 43 S.E.C. 203 (1966).
-------------------------
5 Consolidated National Cas Co., 45 S.E.C. 672 (1990).
-----------------------------
6 Id.
--
7 Northeast Utilities, 42 S.E.C. 963 (1966).
-------------------

<PAGE>
The consideration to be paid to shareholders of the pre-merger
companies was the result of arm's-length negotiations between the management and
financial and legal advisors of Sierra Pacific and Nevada Power over a period of
several months, as detailed in Item 1(B)(3) above. The Boards of Directors of
Sierra Pacific and Nevada Power approved the Transaction in separate meetings
held on April 29, 1998.

In addition, nationally-recognized investment banking firms retained
separately by Sierra Pacific and Nevada Power have reviewed extensive
information concerning the Applicants and analyzed the respective conversion
ratios employing several valuation methodologies. In connection with the
approval of the Merger Agreement, (i) Sierra Pacific's Board of Directors
considered the opinions of its financial advisors, SG Barr Devlin and Merrill
Lynch, to the effect that the aggregate consideration to be received upon
consummation of the Transaction is fair, from a financial point of view, to the
holders of Sierra Pacific Common Stock, and (ii) Nevada Power's Board of
Directors considered the opinion of its financial advisor, PaineWebber, to the
effect that the aggregate consideration to be received by Nevada Power common
shareholders in connection with the Transaction is fair to such holders from a
financial point of view. Each of the fairness opinions of SG Barr Devlin,
Merrill Lynch and PaineWebber are attached hereto as Exhibits H-1, H-2, and H-3,
respectively, and incorporated herein by reference.

In rendering their fairness opinions, SG Barr Devlin, Merrill Lynch
and PaineWebber each performed a number of analyses relevant to the fairness of
the Transaction consideration, including: a comparison of select historical and
projected operating performance data of the Applicants and comparable companies;
a comparison of Sierra Pacific's and Nevada Power's relative contributions to
the total consideration; discounted cash flow analyses; and analyses of the
potential pro forma results of the Transaction. In preparing their opinions, the
financial advisors reviewed, among other things, both public and non-public
historical and projected financial information and forecasts related to the
earnings, assets, business, dividends, cash flow, and prospects of Sierra
Pacific, Nevada Power, and comparable companies. A detailed summary of the
financial opinions is contained at pages 50-64 of the Registration Statement
(Ex. C-1).

Moreover, following the receipt of the Registration Statement
containing these fairness opinions, a majority of both the Nevada Power and

25
<PAGE>
Sierra Pacific common shareholders voted in favor of the Transaction in separate
meetings held on October 9, 1998.

In light of these fairness opinions and considering all
relevant factors, the Applicants believe that the aggregate consideration to be
paid is reasonable and bears a fair relation to the earnings capacity of the
utility assets underlying the Applicants' shares. Accordingly, the consideration
to be paid by Sierra Pacific and Nevada Power meets the standards of Section
10(b)(2).

c. REASONABLENESS OF FEES.

The Applicants believe that the overall fees, commissions, and
expenses incurred and to be incurred in connection with the Transaction are
reasonable and fair in light of the size and complexity of the Transaction
relative to other transactions and the anticipated benefits of the Transaction
to the public, investors, and consumers; that they are consistent with recent
precedent; and that they meet the standards of Section 10(b)(2).

As stated in Item 2 above, Sierra Pacific and Nevada Power together
expect to incur a combined total of approximately $26 million in fees,
commissions and expenses in connection with the Transaction. This amount is
substantially less than the fees associated with recent transactions approved by
the Commission,8 and is consistent with the standards of Section 10(b)(2).

d. CAPITAL STRUCTURE AND THE PUBLIC INTEREST.

Section 10 (b)(3) requires the Commission to determine whether the
Transaction will unduly complicate Sierra Pacific's capital structure or would
be detrimental to the public interest, the interests of investors or consumers,
or the proper functioning of Sierra Pacific's system.

- ---------------

8 See TUC Holding Co., supra. (estimated fees and expenses of $37 mil lion);
Kansas Power & Light Co., Rel. No. 35-25465 (issued February 5, 1992)
(estimated fees and expenses of approximately $30 million); New Century
Energies, Inc., Rel. No. 35-26748 (issued August 1, 1997) (esti mated fees
and expenses of $23.5 million).

26
<PAGE>
Following the Transaction, Sierra Pacific will have a capital
structure which is substantially similar to capital structures which the
Commission has approved in other orders.9 In the Transaction, the shareholders
of Nevada Power and pre-merger Sierra Pacific will receive post-merger Sierra
Pacific Common Stock. The Merger Agreement provides that all outstanding shares
of Nevada Power preferred stock will be redeemed or otherwise retired prior to
the consummation of the Transaction. After consummation of the Transaction,
Sierra Pacific will own 100 percent of the shares of Nevada Power Common Stock,
and will continue to own 100 percent of the shares of SPPC Common Stock. The
Transaction will not affect the outstanding securities of SPPC, including its
first mortgage bonds, junior subordinated debentures, SPPC preferred stock or
SPPC Class A preferred stock. The only issued and outstanding voting securities
of Sierra Pacific will be the Sierra Pacific Common Stock. For these reasons,
the Applicants believe that the Transaction will not unduly complicate Sierra
Pacific's capital structure.

Set forth below are summaries of the historical capital structures
(excluding short-term debt) of Sierra Pacific and Nevada Power as of June 30,
1998, and the pro forma consolidated capital structure of Sierra Pacific and
Nevada Power as of the same date:

- ---------------

9 See, e.g., TUC Holding Co., supra; CINergy Corp., File No. 70-8427, Rel.
No. 35-26146 (issued October 21, 1994); Entergy Corp., File No. 70-8059,
Rel. No. 35-25952 (issued December 17, 1993). In each of these orders, the
Commission approved mergers which resulted in a holding company acquiring
100 percent of a utility operating company's common stock.

27
<PAGE>
<TABLE>
<CAPTION>
Sierra Pacific and Nevada Power Historical Capital Structures
(dollars in thousands)

Sierra Pacific Nevada Power

<S> <C> <C> <C> <C>
Common Stock Equity.............. $651,665 47.0% $826,505 44.9%
Preferred Stock.................. $73,115 5.3% $3,385 0.2%
Preferred Securities............. $48,500 3.5% $118,872 6.4%
Long-term Debt................... $611,936 44.2% $892,858 48.5%
Total Capitalization ............ $1,385,216 100.0% $1,841,620 100.0%
</TABLE>

<TABLE>
<CAPTION>
Sierra Pacific's Post-Transaction Consolidated Capital Structure
(dollars in thousands)
(unaudited)

Sierra Pacific

<S> <C> <C>
Common Stock Equity.............. $1,459,145 39.8%
Preferred Stock.................. $73,115 2.0%
Preferred Securities............. $167,372 4.6%
Long-term Debt................... $1,965,594 53.6%
Total Capitalization ............ $3,665,226 100.0%
</TABLE>

The ratio of consolidated common equity to total capitalization of the
combined companies will be, on an unaudited pro forma basis, 39.8 percent. This
figure exceeds the traditionally acceptable ratio of approximately 30 percent.

As discussed earlier in Item 1(B)(1), the Applicants believe that the
Transaction, by achieving efficiencies and economies, will benefit the interests
of the public, consumers and investors and will not impair the proper
functioning of the holding company system.

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<PAGE>
2. SECTION 10(C).

a. SECTION 10(C)(1).

Under Section 10(c)(1), the Commission must not approve an acquisition
which is "unlawful under the provisions of Section 8" or "detrimental to the
carrying out of the provisions of Section 11." Section 8 prohibits an
acquisition by a registered holding company of an interest in an electric
utility and a gas utility serving substantially the same territory without the
express approval of the state commission when state law prohibits or requires
approval of the acquisition. Section 8 applies only to registered holding
companies and is thus inapplicable to the Transaction. The Nevada PUC issued an
order dated January 4, 1999, approving the Transaction, subject to certain
conditions. A copy of that order is attached as Exhibit D-2.

Section 11(b)(1) requires a registered holding company, with limited
exceptions, to limit its operations to a "single integrated public-utility
system, and to such other businesses as are reasonably incidental, or
economically necessary or appropriate to the operations of such integrated
public-utility system."

Section 2(a)(29) provides separate definitions for "integrated
public-utility system" for gas and electric companies. For electric utility
companies, the term means:

a system consisting of one or more units of generating plants and/or
transmission lines and/or distributing facilities, whose utility
assets, whether owned by one or more electric utility companies, are
physically interconnected or capable of physical interconnection and
which under normal conditions may be economically operated as a single
interconnected and coordinated system . . . .

For gas utilities, the term means:

a system consisting of one or more gas utility companies which are so
located and related that substantial economies may be effectuated by
being operated as a single coordinated system.

With respect to either type of company, the system must be:

29
<PAGE>
confined in its operations to a single area or region, in one or more
States, not so large as to impair (considering the state of the art
and the area or region affected) the advantages of localized
management, efficient operation, and the effectiveness of
regulation[.]10

Section 11(b)(1) permits the acquisition and retention of more than
one integrated utility system only if the requirements of Section 11(b)(1)(A)(C)
are satisfied.

The Commission consistently has recognized that compliance with the
standards of Section 11 is not required where the resulting holding company is
exempt under Section 3. See, e.g., Gaz Metropolitain, Inc., Holding Co. Act
Release No. 26170 (Nov. 23, 1994). Nonetheless, in applying Section 10(c)(1) to
an exempt holding company, the Commission focuses on whether the acquisition
would be detrimental to the core concerns of Section 11, namely the protection
of the public interest and the interests of investors and consumers. WPL
Holdings, 49 S.E.C. 761 (1988), aff'd in part and rev'd in part sub nom.
Wisconsin Environmental Decade, Inc. v. S.E.C., 882 F.2d 523 (D.C. Cir. 1989).
In addition:

The Commission has previously determined that a holding company may acquire
utility assets that will not, when combined with its existing utility
assets, make up an integrated system or comply fully with the ABC clauses,
provided that there is a de facto integration of contiguous utility
properties and the holding company will be exempt from registration under
section 3 of the Act following the acquisition.

WPS Resources Corp., Holding Co. Act Release No. 26922 (Sept. 28, 1998) (citing
BL Holding Corp., Holding Co. Act Release No. 26875 (May 15, 1998); TUC Holding
Co.; Gaz Metropolitain).

The Transaction is fully consistent with the standards of Section
10(c)(1) as applied to exempt holding companies. The merger will combine SPPC's
electric and gas system with Nevada Power's electric system, producing a
combined enterprise that will better serve the needs of its customers and the

- ---------------

10 For gas companies, utilities deriving natural gas from a common source of
supply may be deemed to be included in a single area or region.

30
<PAGE>
interests of its investors by offering more efficient energy supply and delivery
service in competitive markets. The Transaction will not impede the ability of
the Nevada PUC or the California PUC to carry out their statutory
responsibilities with respect to the utility activities of Nevada Power or SPPC.
As noted above, by order dated January 4, 1999, the Nevada PUC approved the
Transaction, subject to certain conditions. The utility operations of the
combined enterprise will continue to be regulated by the Nevada PUC and the
California PUC after the merger.

SPPC's existing gas and electric integrated systems meet the de facto
integration standard. The service territories of SPPC's existing gas and
electric systems overlap. Moreover, the gas and electric systems have been
combined for many years (Sierra Pacific Resources, Holding Co. Act Release No.
24556 (Jan. 28, 1988)) and share corporate services.

The Nevada Power and SPPC electric system will be coordinated to a
significant degree, although for several reasons, the Nevada Power and SPPC
electric systems will not be jointly dispatched. Foremost, as discussed herein,
because Nevada Power and SPPC have agreed to sell all of their generating
plants, they will have no generating plants to dispatch. As discussed below, the
dispatching of generating units located in the Nevada Power and SPPC control
areas initially will be coordinated through an independent scheduling
administrator ("ISA") and eventually through a regional ISO or Transco. In
addition, as a result of electric restructuring in Nevada, retail electric
markets will be fully competitive. Although Nevada Power and SPPC electric
system will not be a single integrated system under the Commission's current
interpretation as it is applied to registered holding companies, an exempt
company need not satisfy the standards of Section 11, nor the requirements of
the ABC clauses. WPS Resources (approving merger of two electric systems which
are not jointly dispatched and which do not constitute a single integrated
system). For the reasons discussed below, the Transaction satisfies the standard
the Commission has applied to exempt companies, namely the de facto integration
standard set forth in TUC Holding Co., and recently applied in WPS Resources.

First, as discussed in Item 1(B) and in the following section,
although the utility systems of Nevada Power and SPPC will "lack[] economic
joint dispatch, the two systems will be coordinated . . .." WPS Resources, at
11. Nevada Power and SPPC will be able to integrate many services, including
accounting and finance, human resources, information services, external
relations, legal and executive administration, customer service, marketing and

31
<PAGE>
sales, and purchasing and materials management. Nevada Power's and SPPC's
transmission systems will be operated pursuant to a joint open access
transmission tariff filed with FERC. Following the proposed divestiture of
generation assets, Nevada Power and SPPC will purchase their power requirements
from a common market the Western System Power Pool. Following the commencement
of retail electric competition in Nevada, retail electric service and metering
service will be offered on a competitive basis. Currently, Nevada Power and SPPC
each provide retail electric service and metering service on a regulated basis.
As a result of the electric restructuring, Nevada Power and SPPC will provide
these services on a competitive basis through a jointly-owned retail service
company and a metering company.

The transmission systems of Nevada Power and SPPC will be coordinated
on a joint basis. As stated above, the Applicants have agreed to join a regional
ISO or Transco within three years. In addition, however, the Nevada PUC's order
approving the Transaction requires the Applicants to submit a proposal for an
interim ISA to the FERC before the merger can take effect. Exhibit D-2 hereto,
p. 82. Initially, Nevada Power and SPPC will be the only members of the ISA. The
ISA will be responsible for accepting and processing all requests for
reservation, scheduling and use of the transmission system, including use of
interconnections to control areas outside Nevada. The ISA will coordinate the
dispatching of generating units located in the Nevada Power and SPPC control
areas, and also coordinate all scheduled outages associated with such
generation. Both the interim ISA and, later, the regional ISO or Transco will be
responsible for directing the dispatch of generating facilities in the Nevada
Power and SPPC service territories for purposes of addressing system
emergencies, managing transmission constraints, meeting reliability criteria and
providing ancillary services. Here, like in WPS Resources, "[t]here are
significant synergies and financial efficiencies between the two systems, and

32
<PAGE>
operations are coordinated to a significant degree." Id. at 12 n.25.11 The
Commission should find that these joint electric system operations satisfy the
de facto integration standard.

Second, while the electric service territories of the Nevada Power and
SPPC public utility systems do not overlap, they "are adjacent and in close
proximity." Id. at 12. In WPS Resources, the service territories of both
utilities were located in Wisconsin's Upper Peninsula region. Likewise, Nevada
Power and SPPC utilities operating in the same region - both are Nevada
utilities with service territories located predominantly in Nevada. Moreover,
both Nevada Power and SPPC serve customers in Nye County, Nevada. The service
territories of Nevada Power and SPPC are separated geographically by 38 miles.
Located between their service territories is federal land, including a Nevada
test site and the Nellis Air Force Base bombing range. These federal facilities
constitute an impediment to direct physical interconnection. A map showing the
transmission systems of Nevada Power, SPPC and the surrounding region is
attached at Exhibit E-4.

Finally, as noted above, the Transaction will produce a combined
entity that will be able to compete more efficiently and effectively in
providing energy services to customers. Thus, the Commission should find that
the Transaction would not be detrimental to the interest of Section 11, and
thereby satisfies the requirements of Section 10(c)(1).

b. SECTION 10(C)(2).

Section 10(c)(2) requires that the Commission not approve an
acquisition unless "the Commission finds that such acquisition will serve the
public interest by tending towards the economical and efficient development of
an integrated public-utility system."

- ---------------
11 The Nevada Power and SPPC systems are not interconnected by a contrac tual
path; due to the utilities' generation divestiture, such means of direct
interconnection is unnecessary for the joint dispatch of the systems.
However, as discussed, the systems will be coordinated via an ISA and
eventually a regional ISO or Transco, providing de facto interconnection of
the systems.

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<PAGE>
The Commission has interpreted Section 10(c)(2) to permit the approval
of acquisitions resulting in more than one integrated system. "[W]e have
indicated in the past that acquisitions may be approved even if the combined
system will not be a single integrated system. Section 10(c)(2) requires only
that the acquisition tend 'towards the economical and the efficient development
of an integrated public-utility system.'"12 The Commission has held that "where
a holding company will be exempt from registration under Section 3 of the Act
following an acquisition of non-integrating utility assets, it suffices for
purposes of Section 10(c)(2) to find benefits to one integrated system."13

In this case, both the Nevada Power and SPPC utility systems will
realize a number of benefits from the Transaction. The Transaction will combine
two companies with complementary operations and expertise, and provide important
strategic, financial and other benefits to the merging companies, shareholders
and customers.

The Transaction will have a number of operational benefits that will
result in economic efficiencies for Sierra Pacific as a whole and for both
utility systems. As discussed above in Item 1(B)(1), Sierra Pacific will
experience economies by combining and coordinating operations with Nevada Power
with respect to corporate functions, including accounting and finance, human
resources, information services, external relations, legal and executive
administration. In addition, the Applicants expect that the Transaction will
result in various cost savings through the integration of corporate programs
(e.g., insurance, advertising), customer support functions (e.g., customer
service, marketing and sales) and competitive utility operations (e.g., retail
electric service and metering service). The operational benefits and
efficiencies associated with the Transaction are estimated at $322 million over
a ten year period, and are discussed in the Registration Statement at pages
45-46. The Transaction also will allow the Applicants to offer a greater range
of services to customers, making the Applicants more competitive, and will
provide significantly increased financial resources to Nevada Power and SPPC,

- ---------------

12 Gaz Metropolitain, Inc., 58 S.E.C. Docket 189, 192, Rel. No. 35-26170 (Nov.
23, 1994) (quoting Union Electric Company, 45 S.E.C. 489, 504-06 (1974),
aff'd without op. sub nom. City of Cape Girardeau v. SEC, 521 F.2d 324
(D.C. Cir. 1975)).

13 TUC Holding Co., supra.

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<PAGE>
making them better able to meet customer needs. The Commission previously has
found that similar benefits satisfied the affirmative finding required under
Section 10(c)(2). See, e.g., WPL Holdings, Inc., 50 S.E.C. 233, 237 (1990)
(benefits supporting Section 10(c)(2) finding include "[a] structure that could
more effectively address the growing national competition in the energy
industry, refocus various utility activities, facilitate selective
diversification into non-utility business . . . and provide additional
flexibility for financing . . ."). Accordingly, the Commission should find that
the requirements of Section 10(c)(2) are satisfied with regard to the
Transaction.

3. SECTION 10(F) -- COMPLIANCE WITH STATE REQUIREMENTS.

To approve an acquisition, the Commission is required, under Section
10(f), to find that the acquisition has complied with all applicable state laws.
The Transaction is conditioned expressly on receipt of all required regulatory
approvals, including that of the Nevada PUC. The Applicants have filed an
Application with the Nevada PUC, a copy of which is filed as Exhibit D-1 hereto.
A copy of the Nevada PUC order dated January 4, 1999, approving the Transaction,
subject to certain conditions, is filed as Exhibit D-2 hereto.

C. SECTION 3(A)(1).

The Applicants believe that, following consummation of the
Transaction, Sierra Pacific and each of its subsidiary companies will be
entitled to exemption under Section 3(a)(1) from all provisions of the Act
(except for Section 9(a)(2) thereof). Section 3(a)(1) authorizes the Commission
to exempt any holding company:

if such holding company, and every subsidiary company thereof which is a
public-utility company from which such holding company derives, directly or
indirectly, any material part of its income are predominantly intrastate in
character and will carry on their businesses substantially within a single
State in which such holding company and every such subsidiary company
thereof are organized.

Following the Transaction, Sierra Pacific and each of its public
utility subsidiaries - Nevada Power and SPPC - will be organized in Nevada.
Further, Nevada Power will earn all of its utility revenues in Nevada and, based
on financial information for the year ended December 31, 1997, SPPC earns more

35
<PAGE>
than 93% of its utility revenues in Nevada. Following the Transaction, Sierra
Pacific will earn approximately 97% of its utility revenues in Nevada. These
amounts are within the existing range of orders issued by the Commission under
3(a)(1) (see Sierra Pacific Resources, Holding Co. Act Release No. 24566 (Jan.
28, 1988)) and well below the percentages of out-of-state utility revenues
presented by holding companies claiming exemption under Rule 2, which claims for
exemption have not been challenged.14

Under such circumstances, Sierra Pacific will qualify as an exempt
holding company, "unless and except insofar as [the Commission] finds the
exemption detrimental to the public interest or the interest of investors or
consumers . . . ." As discussed in Item 1(B)(1), the Applicants believe that the
Transaction will result in efficiencies and economies which will benefit the
interest of the public, investors and consumers. As noted above, the utility
business resulting from the Transaction raises no public interest concerns.
Therefore, the Applicants believe that Sierra Pacific will continue to qualify
for the Section 3(a)(1) exemption upon consummation of the Transaction, and
requests an order from the Commission granting such exemption.

ITEM 4. REGULATORY APPROVAL.

As stated above, the Transaction is conditioned on approval by the
Nevada PUC. Nevada Power and SPPC made a joint application to the Nevada PUC on
July 7, 1998, seeking the necessary approvals of the Merger Agreement and
certain related matters, including the proposed generation divestiture. By order
dated January 4, 1999, the Nevada PUC approved the Transaction, subject to
certain conditions. In an opinion letter, attached as Exhibit F-3, the Sierra
Pacific and SPPC general counsel explains that SPPC was not required to file an

- ---------------

14 See e.g., 1983 Form U-3A-2 filed by Diversified Energies (File No. 69- 271)
(disclosing 22.4% of utility revenues from out-of-state operations); 1998
Form U-3A-2 filed by TNP Enterprises (File No. 69-291) (disclosing 16% of
operating revenues from and 22.7% of retail electricity sales (in MWH) to
out-of-state customers, who comprise 19.5% of all electric customers); and
1998 Form U-3A-2 filed by MidAmerican Energy Hold ings Co. (File No.
69-300) (disclosing 21% of retail gas operating revenues and 12.4% of
electric operating revenues from out-of-state operations and 20.2% of net
gas plant and 11.7% of net electric plant located out-of-state).

36
<PAGE>
application with the California PUC for approval of the Transaction, but SPPC
has agreed to file an application with the California PUC for approval of the
proposed sale of SPPC's generating assets.

On October 2, 1998, SPPC and Nevada Power filed an application with
FERC requesting authorization for the Transaction under Section 203 of the
Federal Power Act. Under Section 203, the FERC will approve a merger if it finds
the mergers "consistent with the public interest." FERC has stated in a Policy
Statement that, in analyzing a merger under Section 203, it will evaluate the
following criteria: (i) the effect of the merger on competition in electric
power markets, utilizing an initial screening approach derived from the DOJ/FTC
Horizontal Mergers Guidelines to determine if a merger will result in an
increase in an applicant's market power; (ii) the effect of the merger on the
applicants' wholesale sales and transmission customers; and (iii) the effect of
the merger on state and federal regulation of the applicants.

The HSR Act, and the rules and regulations thereunder, provide that
certain merger transactions (including the Transaction) may not be consummated
until required information and materials have been furnished to the DOJ and the
FTC and certain waiting periods have expired or been terminated. The Applicants
expect to make the HSR filing in the first quarter of 1999.

ITEM 5. PROCEDURE.

The Applicants respectfully request that the Commission issue and
publish not later than February 19, 1999 the requisite notice under Rule 23 with
respect to the filing of this Application, such notice to specify a date not
later than March 19, 1999, by which comments may be entered and a date not later
than March 22, 1999, as a date after which an order of the Commission granting
and permitting this Application to become effective may be entered by the
Commission.

The Applicants submit that a recommended decision by a hearing or
other responsible officer of the Commission is not needed for approval of the
proposed Transaction. The Division of Investment Management may assist in the
preparation of the Commission's decision. There should be no waiting period
between the issuance of the Commission's order and the date on which it is to
become effective.

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<PAGE>
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS.

a. EXHIBITS.

A-1 Articles of Incorporation of Sierra Pacific (Exhibit B to Exhibit D-1
hereto)

A-2 By-Laws of Sierra Pacific (Exhibit C to Exhibit D-1 hereto)

A-3 Articles of Incorporation of Nevada Power (Exhibit B to Exhibit D-1
hereto)

A-4 By-Laws of Nevada Power (Exhibit C to Exhibit D-1 hereto)

B-1 Agreement and Plan of Merger (Exhibit A to Exhibit D-1 hereto; Exhibit
H to Exhibit D-3 hereto; and filed as Annex A to the Registration
Statement on Form S-4 on September 4, 1998 (Registration No.
333-62895) and incorporated herein by reference)

C-1 Registration Statement of Sierra Pacific and Nevada Power on Form S-4
(filed September 4, 1998 (Registration No. 333-62895) and incorporated
herein by reference)

D-1 Application to the Nevada PUC, filed August 7, 1998, together with
testimony and exhibits (filed herewith on Form SE)

D-2 Order of Nevada PUC approving merger, dated January 4, 1999, and
Clarification Order, dated January 29, 1999.

D-3 Application to FERC, filed October 2, 1998, together with testimony
and exhibits (filed herewith on Form SE)

D-4 Determination of FERC (to be filed by amendment)

E-1 Map of SPPC's service territory (Exhibit I to Exhibit D-1 hereto and
Exhibit SPNP-11 to Exhibit D-3 hereto)

E-2 Map of Nevada Power's service territory (Exhibit I to Exhibit D-1
hereto and Exhibit SPNP-3 to Exhibit D-3 hereto)

38
<PAGE>
E-3 Map showing the service territories of SPPC and Nevada Power (Exhibit
I to Exhibit D-3 hereto)

E-4 Map showing the transmission systems of SPPC and Nevada Power (filed
herewith on Form SE)

E-5 Sierra Pacific organization chart (Appendix 1 to Exhibit D-3 hereto)

E-6 Nevada Power organization chart (Appendix 1 to Exhibit D-3 hereto)

E-7 Combined company organization chart after the Transaction (Appendix 1
to Exhibit D-3 hereto)

F-1 Opinion of Counsel (to be filed by amendment)

F-2 Past Tense Opinion of Counsel (to be filed by amendment)

F-3 Opinion of Counsel of William E. Peterson, Senior Vice President,
General Counsel and Corporate Secretary, Sierra Pacific Resources

G-1 Sierra Pacific's Annual Report on Form 10-K for the fiscal year ended
December 31, 1997 (File No. 1-8788, filed March 30, 1998, amended
September 3, 1998, and incorporated herein by reference)

G-2 Sierra Pacific's Quarterly Report on Form 10-Q for the quarters ended
March 31, 1998, June 30, 1998 and September 30, 1998 (File No. 1-8788
and incorporated herein by reference)

G-3 SPPC's Annual Report on Form 10-K for the fiscal year ended December
31, 1997 (File No. 0-508, filed March 30, 1998 and incorporated herein
by reference)

G-4 SPPC's Quarterly Report on Form 10-Q for the quarters ended March 31,
1998, June 30, 1998 and September 30, 1998 (File No. 0-508 and
incorporated herein by reference)

G-5 Nevada Power's Annual Report on Form 10-K for the fiscal year ended
December 31, 1997 (File No. 1-4698, filed March 23, 1998 and
incorporated herein by reference) G-6 Nevada Power's Quarterly Report
on Form 10-Q for the quarters ended March 31, 1998, June 30, 1998 and
September 30, 1998 (File No. 1-4698, filed November 6, 1998 and
incorporated herein by reference)

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<PAGE>
H-1 Opinion of SG Barr Devlin (filed as Annex C to the Registration
Statement on Form S-4 on September 4, 1998 (Registration No.
333-62895) and incorporated herein by reference)

H-2 Opinion of Merrill Lynch, Pierce, Fenner & Smith Incorporated (filed
as Annex D to the Registration Statement on Form S-4 on September 4,
1998 (Registration No. 333-62895) and incorporated herein by
reference)

H-3 Opinion of PaineWebber Incorporated (filed as Annex B to the
Registration Statement on Form S-4 on September 4, 1998 (Registration
No. 333-62895) and incorporated herein by reference)

I-1 Proposed Form of Notice

b. FINANCIAL STATEMENTS.

FS-1 Sierra Pacific Consolidated Balance Sheet as of December 31, 1997
(previously filed with the Commission in Sierra Pacific Annual Report
on Form 10-K for the year ended December 31, 1997 (Exhibit G-1
hereto), filed March 30, 1998, File No. 1-8788, and incorporated
herein by reference)

FS-2 Sierra Pacific Consolidated Balance Sheet as of September 30, 1998
(previously filed with the Commission in Sierra Pacific Quarterly
Report on Form 10-Q for the quarter ended September 30, 1998 (Exhibit
G-2 hereto), filed November 13, 1998, File No. 1-8788, and
incorporated herein by reference)

FS-3 Sierra Pacific Consolidated Statement of Income for the 12 months
ended December 31, 1997 (previously filed with the Commission in
Sierra Pacific Annual Report on Form 10-K for the year ended December
31, 1997 (Exhibit G-1 hereto), filed March 30, 1998, File No. 1-8788,
and incorporated herein by reference)

40
<PAGE>
FS-4 Sierra Pacific Consolidated Statement of Income for the 9 months ended
September 30, 1998 (previously filed with the Commission in Sierra
Pacific Quarterly Report on Form 10-Q for the quarter ended September
30, 1998 (Exhibit G-2 hereto), filed November 13, 1998 File No.
1-8788, and incorporated herein by reference)

FS-5 Nevada Power Consolidated Balance Sheet as of December 31, 1997
(previously filed with the Commission in Nevada Power Annual Report on
Form 10-K for the year ended December 31, 1997 (Exhibit G-5 hereto),
filed March 23, 1998, File No. 1-4698, and incorporated herein by
reference)

FS-6 Nevada Power Consolidated Balance Sheet as of September 30, 1998
(previously filed with the Commission in Nevada Power Quarterly Report
on Form 10-Q for the quarter ended September 30, 1998 (Exhibit G-6
hereto), filed November 6, 1998, File No. 1-4698, and incorporated
herein by reference)

FS-7 Nevada Power Consolidated Statement of Income for the 12 months ended
December 31, 1997 (previously filed with the Commission in Nevada
Power Annual Report on Form 10-K for the year ended December 31, 1997
(Exhibit G-5 hereto), filed March 23, 1998, File No. 1-4698, and
incorporated herein by reference)

FS-8 Nevada Power Consolidated Statement of Income for the 9 months ended
September 30, 1998 (previously filed with the Commission in Nevada
Power Quarterly Report on Form 10-Q for the quarter ended September
30, 1998 (Exhibit G-6 hereto), filed November 6, 1998 File No. 1-4698,
and incorporated herein by reference)

FS-9 Pro Forma Combined Financial data for Sierra Pacific and Nevada Power
(previously filed with the Commission in the Registration Statement of
Sierra Pacific on Form S-4, filed on September 4, 1998 (Registration
No. 333-62895) and incorporated herein by reference)

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<PAGE>
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS.

The Transaction will not involve major federal action significantly
affecting the quality of the human environment as those terms are used in
Section 102(2)(C) of the National Environmental Policy Act, 42 U.S.C. Section
4321 et seq. ("NEPA"). First, no major federal action within the meaning of NEPA
is involved. Second, consummation of the Transaction will not result in changes
in the operations of Nevada Power or the subsidiaries of Sierra Pacific that
would have any significant impact on the environment. To the Applicants'
knowledge, no federal agency is preparing an environmental impact statement with
respect to this matter.

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<PAGE>
SIGNATURE

Pursuant to the requirements of the Public Utility Holding Company Act
of 1935, the undersigned Applicants have duly caused this Application to be
signed on their behalf by the undersigned thereunto duly authorized.

SIERRA PACIFIC RESOURCES / SIERRA PACIFIC POWER COMPANY:

By: /s/ William E. Peterson Date: 2/9/99
----------------------- ------

Name: William E. Peterson
-------------------

Title: Senior Vice President, General Counsel and Corporate Secretary
--------------------------------------------------------------

NEVADA POWER COMPANY:

By: /s/ Richard L. Hinckley Date: 2/8/99
------------------------ ------

Name: Richard L. Hinckley
-------------------

Title: Vice President, Secretary and General Counsel
---------------------------------------------

<PAGE>
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA

Docket No. 98-7023

In Re Application of NEVADA POWER COMPANY,

SIERRA PACIFIC POWER COMPANY, and SIERRA

PACIFIC RESOURCES for approval of agreement

and plan of merger.

_____________________________________________

At a general session of the Public Utilities Commission of Nevada, held at its
offices on December 31, 1998.

PRESENT:

Chairman Judy M. Sheldrew

Commissioner Lucy A. Stewart

Commissioner Donald L. Soderberg

Commission Secretary Jeanne Reynolds

COMPLIANCE ORDER

The Public Utilities Commission of Nevada ("Commission") makes the following
findings of fact and conclusions of law:

PROCEDURAL HISTORY
1. On July 7, 1998, Nevada Power Company ("NPC"), Sierra Pacific Resources,
and Sierra Pacific Power Company ("SPPCO"or "Sierra") (collectively, "Joint
Applicants") filed a joint application, designated as Docket No. 98-7023,
with the Commission. Joint Applicants sought authorization to implement a
Merger Agreement executed by Sierra Pacific Resources and NPC and to cancel
and convert NPC common stock to Sierra Pacific Resources common stock.
Joint Applicants also requested that the Commission authorize that upon
completion of the merger, the newly-formed company, "Nevada Power Co.,"
shall succeed to all rights and responsibilities under Chapters 703 and 704
of NRS, related regulations and certificates of authority presently held by
NPC. Joint Applicants further requested that the Commission authorize the
transfer of the certificate of public convenience and necessity presently
held by NPC to the merged and surviving company, Nevada Power Co. The
proposed merger includes or contemplates (a) a plan for divestiture of
generation assets, (b) use of the proceeds from the sale of generation
assets to support transmission and distribution improvements, and (c)
amortization of the after-tax gain on the sale of generation assets over
three years, to offset generation-related stranded costs and restructuring
transition costs, with the balance, if any, to be shared with customers
through an incentive rate mechanism. The Merger Agreement contemplates that
NPC will become a wholly-owned, first tier utility subsidiary of Sierra
Pacific Resources. Sierra Pacific Resources is to continue as the parent

<PAGE>
company of SPPCO and become the parent company of the surviving
corporation. The operating utility subsidiaries will maintain their
separate corporate identities and will continue to serve in their
respective service territories in northern and southern Nevada. The joint
application includes a multi-part regulatory rate plan described by the
Joint Applicants as being designed to hold utility customers harmless from
any adverse impact on rates associated with the costs of the merger and a
proposal for an incentive mechanism through which net merger and related
benefits are to be shared between customers and investors.
2. The joint application comes within the purview of the Commission's
jurisdiction pursuant to NRS 704.329, 704.410, and 704.322 to 704.325,
inclusive.
3. The Commission issued a public notice of this joint application in
accordance with State law and the Commission's Rules of Practice and
Procedure. Leave to intervene was granted to the Colorado River Commission
("CRC"); Deseret Generation & Transmission Co-operative ("Deseret"); Mt.
Wheeler Power, Inc. ("Mt. Wheeler"); the Utility Shareholders Association
of Nevada ("USAN"); the Southern Nevada Water Authority ("SNWA"); the City
of Fallon; the United States Department of Energy ("DOE"); the California
Department of Water Resources; Churchill County; Valley Electric
Association. Inc.; the Truckee-Carson Irrigation District; Enron Corp.
("Enron"); Brady Power Partners; Oxbow Geothermal, Inc.; U.S. Energy
Systems, Inc.; Barrick Goldstrike Mines Inc. ("Barrick"); the Nevada
Independent Energy Coalition ("NIEC"); Newmont Gold Company ("Newmont");
Southern California Edison Company; Southwest Gas Corporation; Paiute
Pipeline Company; Southern Energy, Inc./Southern Company Energy Marketing
L.P. ("Southern Companies"); Las Vegas Cogen Ltd. Partnership ("Las Vegas
Cogen"); the Southern Nevada Homebuilders Association; the International
Brotherhood of Electrical Workers/AFL-CIO; Coastal Power Company/Colorado
Interstate Gas Company ("Coastal"); the Mirage/MGM Grand Hotel
("Mirage/MGM"); Excalibur/Luxor/Mandalay Bay; Houston Industries Power
Generation, Inc.; and the Bonneville Power Administration. The Regulatory
Operations Staff of the Commission ("Staff") and the Attorney General's
Office of Advocate for Customers of Public Utilities ("UCA") participated
in this joint application as a matter of right.
4. The Commission conducted a duly-noticed prehearing conference in this
docket on August 27, 1998 (which was continued to September 21, 1998) in
Las Vegas, Nevada. On September 3, 1998, the Commission issued an Order
which continued the prehearing conference, set a date for the filing of
additional information by the Joint Applicants, identified the subject
areas to be addressed in the course of this proceeding, and solicited any
additional subject areas from the parties.
5. On September 11, 1998, the Joint Applicants filed numerous documents under
seal. In a letter and 2-page index which accompanied these documents, the
Joint Applicants generally described the sealed documents and advised the
Commission that they claimed that all these documents were of a
confidential nature.
6. At the continued prehearing conference held on September 21, 1998, the
Presiding Officer determined that a hearing should be held for the limited
purpose of hearing argument and testimony on whether the Commission should
treat the material filed under seal on September 11, 1998 as confidential.
On October 13, 1998, Staff made an informational filing which included the
standards for confidential treatment and the legislative history of the
pertinent statutes. A duly-noticed hearing on this limited issue was held
on October 14 and 23, 1998, in Las Vegas. On November 2, 1998, the
Commission issued an Order which granted the Joint Applicants' request for
confidential treatment for some of these documents and denied the request
for others.
7. On September 30, 1998, the UCA filed a motion to compel and request for
order shortening time, in which it requested that the Commission order the
Joint Applicants to produce all estimates of stranded costs made by the

2
<PAGE>
Joint Applicants for their generating assets or costs, or both, over the
last three years. On October 6, 1998, Staff filed a joinder in the UCA's
motion. On October 12, 1998, Sierra filed its opposition to the motion to
compel, in which it argued that the document which the UCA wanted it to
produce was privileged material. On October 22, 1998, the UCA filed its
reply to Sierra's opposition. On October 23, 1998, the Presiding Officer
granted the UCA's motion to compel. (Tr. of October 23, 1998 at 357.)
Motions to compel production of the documents filed with the Commission
under seal on September 11, 1998 were filed on October 12, 1998 by Las
Vegas Cogen, Coastal, and Mirage; these motions were eventually resolved
through the execution by the parties of protective agreements. SNWA also
filed a motion to compel on October 12, 1998, which was addressed at the
hearing held on October 14, 1998.
8. On November 2, 1998, Staff filed a motion to compel in which it requested
certain information from NIEC. On or about November 4, 1998, NIEC filed its
opposition to Staff's motion. On November 5, 1998, Staff filed its reply to
the NIEC's response. At the commencement of the evidentiary hearing on
November 9, 1998, these two parties advised the Commission that the motion
could be held in abeyance unless and until the parties determined that a
ruling would be necessary.
9. In addition to the prehearing conferences held on August 27, 1998 and
September 21, 1998, and the hearings on the confidential treatment of
certain documents held on October 14 and 23, 1998, an evidentiary hearing
was held on November 9, 10, 16 to 20, 23 to 25, 30, and December 1, 2, and
16, 1998 in both Las Vegas and Carson City. The transcripts from November
9, 1998 to December 16, 1998 contain 3,155 pages in 14 volumes. Exhibits
numbered 1 to 26, 28 to 63, 65 to 88, and 91 to 95 were admitted into the
record. Exhibit 27-C was withdrawn; Exhibits 64, 89, and 90, and part of 87
were stricken. Unless otherwise noted in this Order, references to pages in
the transcripts refer to the volumes beginning November 9, 1998 and ending
December 16, 1998. Staff withdrew Exhibit 27-C (for confidential) during
the course of the hearing. (Tr. at 1024.)
10. On September 17, 1998, the Commission adopted a temporary regulation in
Docket No. 98-5001 which set forth the contents of applications for
authority to merge, acquire through a subsidiary or affiliate, or otherwise
directly or indirectly obtain control of an energy utility.
11. As noted during the prehearing conference held on September 21, 1998, this
proceeding was divided into three phases. Phase 1 involves the structural
features of the proposed merger, the effect of the merger on competition,
and the effect of the merger on existing contracts. Phase 2 addresses the
effect of the merger on costs, rates, and quality of service. Phase 3
concerns the effect of the merger on the Commission's jurisdiction.
12. Staff filed Attachments LD-8 and LD-9 to the prepared testimony of Staff
witness Mr. Lew DeWeese under seal. Staff notified the Commission and the
parties at the commencement of the evidentiary hearing that no confidential
treatment was being requested for these documents. (Tr. of November 9, 1998
at 12.)
13. The prepared direct testimony of a witness for Coastal, that of Mr. Donald
Zinko (Exhibit 44), was admitted into evidence without cross-examination,
upon the motion of the witness' counsel, to which no party objected. (Tr.
at 1726-27.)
14. Staff moved to strike the rebuttal testimony of Joint Applicants' witness
Mr. John McClellan. The UCA joined in this motion to strike, as did SNWA.
The Presiding Officer struck portions of Exhibit 87 and all of Exhibits 88
and 89. (Tr. at 2998-3012.)

3
<PAGE>
POSITIONS OF THE PARTIES

Phase 1 - Structural features of the proposed merger, the effect of the merger
on competition, and the effect of the merger on existing contracts.

Joint Applicants

1. Mr. Michael Niggli, President and Chief Operating Officer of NPC, testified
first for the Joint Applicants. The joint application was marked Exhibit 4;
Mr. Niggli's prepared direct testimony was marked Exhibit 5. Appendix
Volume 1 was marked Exhibit 6; Appendix Volume 2, Exhibit 7. On
cross-examination, Mr. Niggli testified that the merged company does want
to provide any potentially competitive services which it determines will
prove profitable. The Joint Applicants have not finalized their plans with
respect to which potentially competitive services it will seek to offer
because the applicable regulations which will affect the value of entering
such lines of business are not final. (Tr. at 36.) The Joint Applicants
have been advised by Credit Suisse First Boston ("CSFB") that the value of
the generation assets to be sold can be maximized via a two-phase approach
in which preliminary bidding will give them an indication of the degree of
interest in the assets. They intend to then shorten the list of bidders to
those they believe are serious bidders who will provide the best bids. The
second bids solicited from these bidders will be considered final bids.
(Tr. at 37.) The Joint Applicants do not intend to own any generation
assets once they divest, but that situation may change in the future. (Tr.
at 38-39.) Mr. Niggli would not commit to not own any generation assets in
the state of Nevada for any extended period of time. (Tr. at 39-40.) He
believes that an independent system operator ("ISO") or independent
scheduling administrator ("ISA") should mitigate market power problems and
that an ISA should allow all parties to realize their business plans on an
equal basis. (Tr. at 40, 44.) Although the merged company does not intend
to own any generation assets, it may in fact do so if being a provider of
last resort makes it sensible to do so. (Tr. at 42.) The merged company
intends to reinvest the proceeds from the sale of generation assets into
not only transmission and distribution services, but also into energy
services. (Tr. at 42.) Mr. Niggli considers the merger very pro-competitive
because the plan to divest generation assets will allow multiple owners to
enter a market previously controlled by one owner. (Tr. at 44.) The merged
company intends to continue to own and operate its transmission facilities.
(Tr. at 45.) Mr. Niggli agreed that NPC's contracts with qualifying
facilities ("QF contracts") are above market. (Tr. at 53.) These QF
contracts are not part of the generation assets which the Joint Applicants
plan to divest. (Tr. at 53.) The merged company envisions that customers of
distribution service will continue to bear the costs associated with these
contracts. (Tr. at 53-54.) Mr. Niggli does not believe that approval by the
Commission of the divestiture plan as proposed will affect subsequent
decisions related to stranded investment. (Tr. at 58.) If the Commission
were to decide that the costs of all generation assets should be netted
(above market netted with below market), such a decision might conflict
with the divestiture plan as proposed in this joint application. (Tr. at
58-60.) Mr. Niggli expects multiple entities to successfully bid for the
generation assets and does not expect to end up with a single owner of all
the assets. (Tr. at 61.) He believes two or three owners of NPC's
generation assets would be sufficient to alleviate concerns about market
power, although he admitted this estimate is not based on specific market
power indications. (Tr. at 62.) The Joint Applicants have not made plans on
how they will fulfill their contractual obligations with the QFs. (Tr. at
65-67.)
2. On further cross-examination, Mr. Niggli testified that he wanted to find a
way for NPC to reduce its dividend without adversely affecting the stock
price. (Tr. at 73.) This goal was accomplished through a strategic

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repositioning, i.e, the merger, of the company, which was well received by
Wall Street. (Tr. at 73.) Mr. Niggli believes the joint application itself
defines the divestiture proposal. (Tr. at 88.) He later described the
divestiture plan as a living document which is subject to modification.
(Tr. at 93.) The Joint Applicants would not accept a conditional approval
of the merger which involves consideration and approval of a comprehensive
final divestiture plan in a separate proceeding, because the time frame for
conclusion of such a proceeding is unknown. Mr. Niggli believes that the
Joint Applicants' proposal will allow for the onset of competition by the
end of 1999. (Tr. at 98.) If the Commission were to impose such a
condition, the Joint Applicants would have to reconsider their decision to
merge. (Tr. at 99.)
3. Upon questioning by the Commission, Mr. Niggli testified that he is unsure
that the merged company would be able to provide billing and customer
services on a competitive basis with other entities which presently provide
such services. The Joint Applicants' plans are not final in terms of which
potentially competitive services it intends to form affiliates to provide.
(Tr. at 102.) At this time the merged company intends to provide billing
and customer services only for its own affiliates. Mr. Niggli believes this
can be done without raising antitrust concerns. (Tr. at 105, 118, 121.) Mr.
Niggli considers purchased power contracts a subset of generation
resources. If the merged company retains its purchased power contracts, it
will have to either form a generation affiliate or transfer control of the
assets to an ISA. (Tr. at 110.) For all proceeds from the sale of
generation assets up to book value, the Joint Applicants want to be able to
reinvest the proceeds in transmission, distribution, energy services, debt
retirement, and repurchase of equity. (Tr. at 122.) Mr. Niggli believes the
proceeds from generation assets, which were paid for by ratepayers, should
be available to the corporation to use as it sees fit. (Tr. at 122-23.) He
does not envision having the Commission review how the proceeds from the
sale up to book value might be used. For any proceeds above book value that
are obtained, a proposal has already been made. (Tr. at 123-24.) He
believes the merged company will be financially stronger and more resistant
to acquisition by another utility in the future. (Tr. at 132-33.) He
admitted there is no assurance that the merged company will not be acquired
anyway. (Tr. at 133.) Absent the merger, NPC might consider competing in
Sierra Pacific's territory. (Tr. at 136.) With the merger, one potential
competitor is removed from the picture. (Tr. at 137.) Mr. Niggli hopes the
merger will result in a stronger company who will better compete with other
entrants into the market. (Tr. at 137.) It would be important, but not
essential, for the Commission to approve the Joint Applicants' ISA proposal
before it is filed with the Federal Energy Regulatory Commission ("FERC").
(Tr. at 138, 141.) He agreed that the Joint Applicants are not requesting
approval of the actual process by which divestiture will be accomplished,
although they are requesting approval to divest the assets. (Tr. at 142.)
4. Mr. Malyn Malquist, Chairman of the Board, President, and Chief Executive
Officer for Sierra Pacific Resources and Sierra Pacific Power Company,
testified next. His prepared direct testimony was marked Exhibit 10. On
cross-examination, Mr. Malquist agreed that potential new suppliers of
generation will need to feel comfortable that they will have unfettered
access to the transmission grid before making the investment necessary to
build new generation. (Tr. at 147-48.) Assuming a generation affiliate is
formed, the merged company does not intend to have that affiliate hold the
purchased power agreements or QF contracts which the two utilities
presently hold. The merged company intends to charge the costs associated
with these agreements as an adder to distribution or transmission charges.
(Tr. at 149-50.) The Joint Applicants intend to keep the two utility
companies separate following the merger. (Tr. at 163.) If the generation
assets are sold above book value and the proceeds are used to offset some
of the QF contracts, distribution and transmission charges would be lower.
The Joint Applicants have not proposed this type of netting. (Tr. at 170.)
The Joint Applicants expect approximately $1 billion in proceeds from the

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sale of generation assets. The construction budget for the merged company
is in the range of $300 to $350 million. With the remainder, the merged
company might retire debt and buy back stock. (Tr. at 181.)
5. However, neither of these options result in a return as high as what can be
realized from investing in expansion of transmission and distribution. (Tr.
at 181.) Upon questioning by the Commission, Mr. Malquist admitted that the
joint application lacks information about the ultimate corporate structure
and organization of upper management following the merger. He and Mr.
Niggli are still working on the final structure. (Tr. at 185.) Mr. Malquist
does not consider purchased power part of generation. (Tr. at 189.) He
believes an appropriate way to handle the QF and purchased power contracts
is to have their costs allocated to distribution service. (Tr. at 190-91.)
He considers it essential that the Commission have input on the structure
of an ISA. (Tr. at 193.)
6. Mr. Steven Oldham, Vice President of Transmission Services and Strategic
Development for Sierra Pacific Power Company, testified next. His prepared
direct testimony was marked Exhibit 11. Section II-D of this testimony was
withdrawn. On cross-examination, Mr. Oldham agreed that the Joint
Applicants did consider and evaluate the assets which are the QF contracts
in connection with this joint application. (Tr. at 209.) He clarified that
the testimony which was withdrawn is still the Joint Applicants' position;
the decision to withdraw the testimony from this proceeding concerns the
timing of its consideration. (Tr. at 209-10.) Mr. Oldham knows of no plans
to acquire generation facilities outside the state of Nevada. (Tr. at
212-13.) He could not say whether in the future the merged company will
seek to acquire generation facilities. (Tr. at 216-17.) He believes that
FERC Order 888 and the tariff which Sierra filed with FERC in July 1996 are
adequate to ensure access to the transmission system. (Tr. at 223, 245.)
Mr. Oldham did not agree that the administrator of an ISA needs to be a
truly independent entity in order to foster the desire on the part of
generation companies to enter the Nevada market. (Tr. at 225.) Mr. Oldham
testified that uncertainty surrounding Commission policies affects the
marketability of generation assets, but disagreed that the value of such
assets would be maximized if the divestiture process were delayed until
after restructuring is completed. (Exhibit 11, p. 12; Tr. at 251-52.) He
believes certain risks will be present even after restructuring. (Tr. at
252-54.) Mr. Oldham stated the Joint Applicants' ability to divest is tied
to their ability to retain shareholder value. He considers the proposed
merger critical to the ability to divest without losing shareholder value.
(Tr. at 254-55.) He agreed that the joint application contains no assurance
that all proceeds from the sale of generation assets will not be used to
either retire debt or buy back equity. (Tr. at 255-56.) Mr. Oldham
testified that Sierra Pacific Power Company has sufficient transmission and
generation in its service territory to meet its load, but admitted that
during the summer of 1998 it asked Newmont to back down its load by
approximately 40 megawatts. It made similar requests of other customers.
Most of the contracts Sierra has under its GS-4C or GS-5T tariffs run
beyond the year 2000. The merged company wants to continue to serve these
customers, but Mr. Oldham did not specify how it will do so. (Tr. at
262-67.) If the Commission were to require that the Joint Applicants file a
rate case and have it resolved prior to consummating this merger, such a
condition might be unacceptable because of the timing involved in
conducting a rate case. (Tr. at 265.) The Joint Applicants want an order on
this merger to enable them to recover the costs of the transaction. (Tr. at
266.) Mr. Oldham expects the plan to seek multiple owners of the generation
assets to result in a lower value for the assets but a higher degree of
competition. (Tr. at 269.) He could not specify how Sierra Pacific will
fulfill its contract obligations after the merger and the onset of retail
competition. (Tr. at 271-73.) Sierra believes the costs associated with its
purchased power contracts should remain in bundled rates, even if they must
appear as a separate line item. (Tr. at 281.) Mr. Oldham described the
charges to be assessed as "additional transmission costs" to be recovered

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from all customers. (Tr. at 281-82.) The merged company intends to honor
purchased power contracts just as it intends to honor contracts with large
customers. (Tr. at 285.) The merged company's load could not be met without
these purchased power contracts. (Tr. at 285-86.) The generation supplied
to the grid from purchased power agreements should be shared
proportionately by all aggregators and energy service providers who make
retail sales to customers in Nevada. The allocation of associated
generation costs should be made in the same proportion. (Tr. at 286-87.)
Mr. Oldham testified that the merged company could form an affiliate to buy
power from entities such as QFs and resell this power; he was unsure
whether the company would have to form an affiliate to perform this
function. (Tr. at 297-98.) The Joint Applicants are committed to either
joining a regional ISO or forming an independent transmission company
within three years and would accept being required to do so by the
Commission in connection with approval of this merger. (Tr. at 306.) The
merged company plans to invest $948 million in transmission facilities in
Northern Nevada following the divestiture. (Tr. at 308.) Mr. Oldham
testified that one way to deal with the costs of purchased power contracts
and QF contracts would be to require those who sell to retail or wholesale
customers to buy a portion of their total supply from a pool of purchased
power contracts and have the aggregators themselves pass the charges on to
customers. (Tr. at 311, 313-14.) The Joint Applicants are not requesting
approval of any investment in transmission facilities in connection with
this joint application. (Tr. at 362.)
7. Upon questioning by the Commission, Mr. Oldham agreed that, because of the
presence of load pockets, the Commission has a legitimate concern about the
level of price control that needs to be established prospectively for
retail customers. (Tr. at 369.) He disagreed that the Joint Applicants'
proposal is to divest generation assets only if the Commission approves
this merger as proposed. (Tr.. at 372-74.) He did state that if the
Commission's decision serves to modify the proposed merger in some fashion,
the Joint Applicants will have to consider the ramifications of any
modifications before deciding whether to actually merge. (Tr. at 374.) Mr.
Oldham testified that Sierra has not made final determinations concerning
how it will honor the contracts it has with large customers because it does
not know what rules will prevail in the restructured environment. (Tr. at
396.) Sierra has not done a business case analysis concerning which classes
of customers it wants to serve in the competitive marketplace because it
first needs to know all the rules under which service is to be offered.
(Tr. at 400-02.) He admitted that the joint application does not contain
the merged company's plans for dealing with the issue of how to honor
current service contracts during the transition from a noncompetitive
environment to an effectively competitive one. (Tr. at 404.) Mr. Oldham
does not consider the costs associated with above-market QF contracts
stranded costs because he considers the obligations in these contracts
ongoing obligations which the Joint Applicants are not proposing to divest.
(Tr. at 404-05.) He envisions seeking stranded cost recovery of costs
associated with assets of which the company relinquishes control. (Tr. at
405.)
8. Mr. Matt Davis, Division Director of System Planning and Operations for
NPC, testified next. His prepared direct testimony was marked Exhibit 12.
He made some changes to this testimony when he took the witness stand. (Tr.
at 429-30.) On cross-examination, Mr. Davis testified that NPC can
currently generate only about 2,000 megawatts of capacity and currently
imports another 1,700 and 2,000 megawatts. Sierra Pacific also imports to
meet its load. (Tr. at 433.) He agreed that both transmission and
generation are deficient in Nevada. (Tr. at 434.) Some of the contracts NPC
has executed with the CRC do not require written approval to assign the
contract to another entity; some do have this requirement. (Tr. at 444-50.)
Mr. Davis understands that all contracts which NPC currently holds will be
assumed by the new company, "Nevada Power Co." (Tr. at 454.) The 235

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megawatts which NPC is entitled to purchase under the Hoover contract
represents about ten percent of generation capacity. (Tr. at 456-57.) Mr.
Davis could not say whether the new merged company will be in a position to
fulfill certain obligations now embodied in contracts with CRC once the
merger is consummated and retail competition has begun. (Tr. at 464-65,
470-71.) The Joint Applicants wish to remain as control area operators
after the merger is completed and they have divested their generation
assets. Mr. Davis insisted that the merged company can accomplish this even
though it will own no generation resources by purchasing generation. He
agreed that a control area operator needs generating resources to ramp up,
ramp down, and provide reactive power. (Tr. at 495.) He believes an ISA is
needed primarily to manage the limited import capability of the two
respective control areas. (Tr. at 496.) He does not believe the Joint
Applicants' plans in this regard create the potential for anticompetitive
behavior, because the rules governing the ISA can cover such situations.
(Tr. at 496-98.)
9. Mr. Thomas Osborne of CSFB testified next. The affidavit submitted in
connection with the hearing held on October 14, 1998 for the purpose of
determining whether certain documents should remain confidential had
previously been marked Exhibit 1. On cross-examination, Mr. Osborne
testified that CSFB was initially hired to review ways to reduce the costs
of the QF contracts through securitization or issuance of securitization
bonds and undertook financial analysis and valuation work toward that end.
(Tr. at 503.) The QF contracts were never considered part of the assets to
be divested. (Tr. at 506.) An analysis was conducted which concluded that
there would be insufficient premium value in the sale of power plants to
offset the potential market value of the QF contracts. This analysis
indirectly contributed to the development of the divestiture proposal
contained in this joint application. (Tr. at 516-17.)
10. Upon questioning by the Commission, Mr. Osborne recognized that the
regulatory authority might consider the costs associated with QF contracts
as potential stranded costs even if the Joint Applicants do not. (Tr. at
554-55.) Although he has been informed by NPC that Commission approval of a
divestiture plan is unnecessary, Mr. Osborne testified that regulatory
approval of the plan would lend certainty to the process and increase the
value of the assets to be divested. (Tr. at 557.)

Southern Companies
1. Mr. James Ronald Harris, Vice President of External Affairs and Assistant
Corporate Secretary for Southern Energy, testified for the Southern
Companies. Mr. Harris adopted the prepared direct testimony of Kim Heinz,
which was marked Exhibit 18. Mr. Harris's qualifications were marked
Exhibit 19. On cross-examination, Mr. Harris testified that building more
transmission facilities would enhance competition in the state. (Tr. at
574.) The Southern Companies currently sell wholesale power to NPC and
intend to compete in other areas as well. (Tr. at 575.) Mr. Harris stated
that generating assets are more valuable when they are sold in large
blocks. (Tr. at 580.) The Southern Companies believe, based on their
experience with auctions, that while the Joint Applicants' plan to limit
prospective buyers to small increments may have been intended to mitigate
market power, such a plan will actually stifle competition because it will
limit the number and size of respondents. (Tr. at 580-81.) Mr. Harris
believes the divestiture of generating assets will help to develop the
competitive wholesale markets, which is where the Southern Companies' sole
interest in this proceeding lies. (Tr. at 585.) While the Southern
Companies have no current plans to build new generation in the state, Mr.
Harris could not say whether such projects might be taken up in the future.
(Tr. at 585.)
2. On redirect examination, Mr. Harris confirmed that Southern Companies are
not in the retail business now and do not intend to be in it in the future.
(Tr. at 598.) Upon questioning by the Commission, he explained that the

8
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Southern Companies want to compete in the wholesale market in the West.
(Tr. at 601.) In order to promote a competitive market, it would be
necessary for more than one buyer to purchase the generating plants. (Tr.
at 605-06.)

Mirage/MGM
1. Mr. Douglas Burton, Chairman of Acarus Group, a consulting firm dealing
primarily in natural gas and electric power transactions, testified on
behalf of Mirage/MGM. His prepared direct testimony was marked Exhibit 20.
He made one correction to this testimony when he took the witness stand.
(Tr. at 612.) On cross-examination, Mr. Burton explained that his clients
want more clarification and details on how this merger will interact with
restructuring and support the merger with conditions. (Tr. at 615.) The
Mirage/MGM believe that who ultimately owns the generating assets could
affect quality of service. (Tr. at 630.) Mr. Burton expressed concern that
this joint application appears to attempt to decide some issues as part of
approving this merger rather than have them considered separately by the
Commission itself. (Tr. at 643.) He considers an ISA or some type of
scheduling coordinator essential to the development of competition in this
state. (Tr. at 651.) He understands that the Joint Applicants have proposed
the formation of an interim ISA which would operate independently of
suppliers of generation and retailers. (Tr. at 654.) Mr. Burton believes
the Commission should consider a sharing mechanism, between ratepayers and
shareholders, for amounts determined to be stranded costs. (Tr. at 670.) He
believes the divestiture of assets should follow, not proceed, unbundling.
(Tr. at 679.) He does not believe coupling the decision on this merger with
a decision on the divestiture of generation assets is in the public
interest. (Tr. at 683.) He had understood that affiliates of the Joint
Applicants might bid for the generating assets; he agreed that now this is
not the case, therefore, some degree of uncertainty is removed from the
merger and divestiture proposal. (Tr. at 686.)
2. Upon questioning by the Commission, Mr. Burton stated, with respect to the
QF contracts, he is concerned that approval of this merger might be
construed later on as some type of final determination of the treatment of
such contracts. (Tr. at 694-95.) He thinks more information is needed as to
how various contracts the Joint Applicants currently have will be handled
before a merger is given final approval. (Tr. at 700.)
3. Mr. Mark Garrett, an attorney and public utility regulation consultant,
testified next for Mirage/MGM. His prepared direct testimony was marked
Exhibit 21. On cross-examination, Mr. Garrett testified that he considers
the joint application unclear on whether revenue requirements will be
adjusted as a result of the rate case which is part of the compliance
filing (NRS 704.986); they do need to be adjusted. (Tr. at 709-11.) Mr.
Garrett recommends that divestiture follow the compliance filing rate case.
(Tr. at 714.) He considers the joint application and accompanying testimony
unclear on the way stranded costs will be determined; the application
suggests that the companies intend to make certain decisions before the
Commission itself has had an opportunity to review this issue. (Tr. at
726.) Mr. Garrett believes the Joint Applicants are attempting to justify
recovery of the acquisition premium, or goodwill, based upon various hold
harmless provisions. (Tr. at 731.) He considers a commitment to freeze
rates, when rates should actually be reduced, a hollow type of hold
harmless provision. (Tr. at 731-32, 765.) It's clear to the witness that
the Joint Applicants have proposed to recover the acquisition premium
through rates because they have proposed amortizing the premium to Account
425, an above-the-line account. (Tr. at 735-36.) The Joint Applicants have
not proposed a mechanism for tracking costs and savings associated with the
merger; Mr. Garrett considers it difficult to track costs and even more
difficult to track savings. (Tr. at 739.) The Joint Applicants have
requested establishment of a return on equity ("ROE") of 12 percent in
connection with the proposed sharing mechanism. (Tr. at 745.) If an

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appropriate ROE based on current market conditions is 8.5 percent, he would
consider 9 percent an appropriate ROE for sharing purposes. (Tr. at 747.)
With respect to crediting accumulated depreciation, Mr. Garrett testified
any after-tax gain should be credited entirely to ratepayers by crediting
the gain directly to the depreciation reserve, or flowing it back through
over some period of time. (Tr. at 747.) He suggests that the Commission
require the Joint Applicants to invest proceeds from the sale of generating
assets in needed transmission facilities in order to alleviate load pocket
situations. (Tr. at 751-52.)
4. On redirect examination, Mr. Garrett expressed his concern that approval of
this joint application might be construed later to preclude the
Commission's ability to make decisions on certain issues such as the
disposition of QF contracts. (Tr. at 754.) On recross-examination, he
agreed that if certain customers of the Joint Applicants take service under
contracts which are due to expire after the onset of retail competition,
some kind of open season might in fact be appropriate. (Tr. at 729, 758.)
Mr. Garrett believes Nevada law contemplates netting above market costs
with those that are below market in terms of stranded costs. (Tr. at 759.)
He testified that unbundling, where appropriate costs are assigned to each
function before divestiture, is necessary so that a utility will not have
an easy way of moving inappropriate costs to captive customers. (Tr. at
770.)

Coastal
1. Coastal presented Mr. Aviv Goldsmith, Director of Coastal's project power
development efforts in Nevada. His prepared direct testimony was marked
Exhibit 22. On cross-examination, he confirmed that Coastal plans on
building new generation in Sierra's service territory. (Tr. at 778.) The
company has also done some preliminary site investigation in southern
Nevada. (Tr. at 781.) Mr. Goldsmith confirmed that Coastal does not
anticipate being ready to enter the market by January 2000, but believes
his company will be ready to serve the mines in northern Nevada when their
contracts with Sierra expire. (Tr. at 782-83.) Coastal's main concern
relates to transmission access and the potential for affiliates to behave
in a noncompetitive manner. Mr. Goldsmith believes a strong ISA can
mitigate some of these concerns. (Tr. at 787.) Coastal believes that an ISA
should have an independent board and eventually become an independent
operator. (Tr. at 788.) Coastal has not decided whether it will participate
in the auction process for generating assets; its decision will depend on
the structure of the sale and on which assets are to be sold. (Tr. at 789.)
2. Upon questioning by the Commission, Mr. Goldsmith testified that if the
merger is approved, the Commission will lose the opportunity to compare the
two utilities to each other as competitors and have one serve as an
example. (Tr. at 803.) The Joint Applicants have expressed a desire to
provide energy services, but the application lacks detail on this plan.
(Tr. at 805.) Broadly speaking, Coastal favors a strong ISA which exercises
a good deal of control over dispatch and which has an independent board; at
some point in the future it should move to an ISO. (Tr. at 806.)

Las Vegas Cogeneration
1. Las Vegas Cogen presented Mr. Benjamin Campbell, President, as a witness.
His prepared direct testimony was marked Exhibit 23. On cross-examination,
he explained that Las Vegas Cogen has assumed that its QF contract with NPC
will remain with the distribution company after the onset of retail
competition. He also expects his contract to become part of the pool of
stranded costs. (Tr. at 820-21.) He anticipates that NPC will work with the
ISA to schedule delivery of the power from his contract to the system, with
NPC buying the energy. (Tr. at 823-24.) He could not say whether the law
would allow an electric distribution utility to purchase and sell energy
after restructuring. (Tr. at 824.) Mr. Campbell stated that the merger
itself does not affect Las Vegas Cogen or the terms of its contract. Las

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Vegas Cogen is willing to discuss a buy-out of this contract. (Tr. at 827.)
NPC and Las Vegas Cogen have engaged in buy-out discussions. (Tr. at
827-28.) He agreed that, to date, neither party has been able to achieve
the benefits it hoped to achieve from these negotiations. (Tr. at 829.)
2. Upon questioning by the Commission, Mr. Campbell stated that this merger
and restructuring are interconnected. (Tr. at 829-30.) His company's main
concern is which company his contract will be with in the future. (Tr. at
830.) He would be concerned if the assets associated with his contract were
assigned to an affiliate; his concerns center around the creditworthiness
and financial strength of the affiliate. (Tr. at 833.) The joint
application is unclear with respect to how his contract will be treated in
the future. (Tr. at 834-35.)

Regulatory Operations Staff
1. Staff presented Mr. Lew DeWeese, Senior Financial Analyst, as its first
witness. His prepared direct testimony was marked Exhibit 24. He made one
change to this testimony when he took the witness stand. (Tr. at 840.) On
cross-examination, Mr. DeWeese confirmed that he is concerned about whether
certain tax-exempt bonds which NPC has issued will retain their tax-exempt
status once the merger is consummated. The company's tax-exempt status
might also be in jeopardy due to reorganization of operations and
employees. (Tr. at 845.) NPC has sought advice from its bond counsel; Mr.
DeWeese believes a ruling from the Internal Revenue Service ("IRS") is
needed because bond counsel's preliminary conclusion is uncertain. (Tr. at
846.) The financial impact of the loss of tax-exempt status could reach $8
million per year. (Tr. at 850.) Staff has not taken a position on the
appropriate treatment of any increased costs which may stem from the loss
of tax-exempt status. (Tr. at 851.) With respect to Sierra Pacific, Mr.
DeWeese understands that Sierra does not intend to complete the divestiture
process until appropriate releases are secured from first mortgage
bondholders. He understands NPC plans on following this same route. (Tr. at
862.) Staff recommends that the Commission require the companies to submit
the final opinion of the trustee for the bondholders which allows the
releases. (Tr. at 863.)
2. Staff presented Mr. Whitfield Russell, a principal with Whitfield Russell
and Associates, next. His prepared direct testimony was marked Exhibit 26.
He made some corrections to this testimony when he took the witness stand.
(Tr. at 1020-22.) On cross-examination, he stated that while he knows the
QF contracts are above market, he has not determined the degree to which
they are above market. (Tr. at 1025.) The auction of the assets to be
divested will determine the extent to which any above market assets or
obligations may be offset by those that are below market. (Tr. at 1025-26.)
The divestiture plan needs to be reviewed in a separate proceeding with
attention paid to the bundles being offered. The load pocket situation in
Nevada requires that the details of divestiture be carefully specified so
as not to create market power problems. (Exhibit 26; Tr. at 1029.) He has
not attempted to determine what the correct number of bundles should be;
that determination needs to be made later. (Tr. at 1029-30.) Mr. Russell
testified that generation capacity in northern Nevada amounts to
approximately 1,700 to 2,000 megawatts; net imports are limited to 360 at
present. In southern Nevada it amounts to approximately 2,000 megawatts; an
additional 2,000 are imported. (Tr. at 1053-54.) The sale of existing
generation assets within the load pocket in northern Nevada to only a few
buyers would create opportunities for collusion, depending on how the
bundles are distributed. (Tr. at 1054.) He does not believe the number of
megawatts which a generating entity has is what makes for efficiency. (Tr.
at 1055.) Mr. Russell's preferred ISO or ISA is one which protects
competitors and consumers by transferring control from an owner of
transmission to an independent body. (Tr. at 1060.) Because the output from
the Valmy plant is known to be the least expensive source of power, there
should ideally be more than one owner of this plant. Otherwise, an owner

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will know that he can raise the price of this power with impunity. This
requirement also applies to other generating units where market power can
be exercised at certain periods of time or for certain blocks of load. (Tr.
at 1062-63.) Mr. Russell does not believe that Mr. Oldham's recommendation
to have any gain on the sale of generation assets amortized over three
years and first used to offset stranded costs related to the designation of
energy as a potentially competitive service comports with NRS 704.983,
because this recommendation fails to subtract stranded costs associated
with QF contracts. (Tr. at 1115.) It is not necessary to project what the
residue might amount to after proceeds are applied to fuel, transportation,
and other costs of making energy potentially competitive, because the
divestiture process will reveal these numbers. (Tr. at 1121.) Maximization
of price in the sale of assets should not be the sole criterion, because it
will likely lead to concentrated ownership of generation. (Tr. at 1122.)
Mr. Russell considers divestiture of generation assets in the public
interest; however, any divestiture must have conditions imposed on it to
prevent abuses of market power. (Tr. at 1167.) The development of a
competitive market requires the sale of generating plants, particularly
those of Sierra. (Tr. at 1170.) Divestiture is desirable because it defers
vertical use of vertical power. But once divestiture has been accomplished,
one needs to consider horizontal market power among competing generating
entities. (Tr. at 1173.) A divestiture which is not properly conditioned
may prove quite detrimental to ratepayers. (Tr. at 1182-83.) Expanding a
transmission system may not be a positive step toward promoting competition
if the cost of expanding exceeds the cost of increasing generation in the
area. (Tr. at 1207.) While the proposed merger and plan for divestiture
reduce vertical market power, they do not eliminate it. (Tr at 1212.) The
sale of the generation assets with or without the merger presents certain
problems. The sale might be structured in a way which will lead to
anti-competitive conduct between Sierra and an affiliate alternative
seller. (Tr. at 1214-17.) Structuring the sale in a way that maximizes
competition might reduce the net proceeds to be realized; a balance needs
to be struck. (Tr. at 1219.)
3. Upon questioning by the Commission, Mr. Russell confirmed that while he
does not wish to dictate the number of bundles of generating assets to be
sold, the Joint Applicants have proposed that they be sold in too few
bundles (three bundles in the North, four in the South). (Tr. at 1238-39.)
Based on Section 201(b) of the Federal Power Act, which provides that FERC
shall not have jurisdiction over facilities used for the generation of
electric energy and over facilities used in local distribution, the
divestiture of generation assets is probably jurisdictional to this
Commission. With respect to the sale of any assets which might be
jurisdictional to FERC, there might be shared jurisdiction. (Tr. at 1246.)
With respect to the Joint Applicants' proposal to divest generating assets
but remain the control area operator, Mr. Russell explained that a control
area operator has knowledge of all schedules for power coming in and going
out and on whose behalf business is being conducted. An operator might be
able to favor an affiliate over other competitors. (Tr. at 1248.)
4. Staff presented Mr. Michael Greedy, Regulatory Analyst in the Financial
Analysis Division, as another witness. His prepared direct testimony was
marked Exhibit 33. He made some corrections to this testimony when he took
the witness stand. (Tr. at 1375.) On cross-examination, Mr. Greedy
testified that he understands that, after a meeting attended by certain
parties to this proceeding which was held in late September 1998, Staff had
more information about the Joint Applicants' plan for divestiture. (Tr. at
1380-82.) Mr. Greedy had not seen a final description of the assets to be
auctioned at the time he testified. (Tr. at 1384-86.) He does not believe
there is enough material in the joint application from which to discern
whether the divestiture plan is appropriate. (Tr. at 1395, 1417.) The terms
of the offering memorandum are critical to how a potential bidder will make
his bid. The process may influence the divestiture plan. Mr. Greedy does

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not believe the Commission will be in a position to properly review the
divestiture plan without the offering memorandum. (Tr. at 1405-06.) He
recommends that the divestiture plan be considered anew in a separate
docket and that any final approval of the merger follow approval of this
plan. (Tr. at 1406-07.)
5. On redirect examination, Mr. Greedy confirmed that the joint application
itself does not contain a comprehensive plan for divestiture. (Tr. at
1436-37.)
6. Upon questioning by the Commission, Mr. Greedy stated that while he is
aware that the Joint Applicants have identified labor force separation as
an issue to be addressed, he has not seen how they plan to address it.
Likewise, none of the material he has reviewed has revealed a plan for
operational coordination among divested plants or a reconciliation of
generation divestiture with issues which relate to integrated resource
planning. Also missing is information on the coordination of the
divestiture of generation assets with a generation aggregation tariff. (Tr.
at 1444.) Mr. Greedy understands that once the generating plants are sold,
they will come under the FERC's jurisdiction for the purpose of setting
rates. (Tr. at 1447-48.) He agreed that this Commission has a genuine
interest in knowing the terms and conditions under which Nevada ratepayers
will receive generation services. (Tr. at 1448.) The Commission has similar
responsibilities with respect to the formation of an ISA. (Tr. at 1449.)
7. Staff called Dr. Dan Berry, Staff Economist in the Regulatory Policy and
Market Analysis Division, as its next witness. His prepared direct
testimony was marked Exhibit 39. He made some corrections to this testimony
when he took the witness stand. (Tr. at 1453-54.) On cross-examination, Dr.
Berry confirmed that owners of generation facilities do not presently have
the ability to exercise market power because their prices are regulated.
(Tr. at 1455.) If these assets are divested in the manner suggested by the
Joint Applicants, there is a strong possibility that the new owners will be
able to exert market power. (Tr. at 1455-56.) The generation aggregation
tariff which Staff has designed is intended to constrain prices in the
absence of effective competition. (Tr. at 1457.) Dr. Berry agreed that in
light of the potential exercise of market power by new owners, the
Commission should condition this merger on the implementation of regulatory
devices to protect customers. (Tr. at 1459.) He pointed out that the joint
application does not include any information about which potentially
competitive services the Joint Applicants intend to offer via affiliates.
(Tr. at 1464.) Staff considers this information valuable because it would
give Staff and the Commission an idea of the number of providers to expect
in a market; this proposed merger removes one potential competitor in
retail services in each of the Joint Applicants' markets. (Tr. at 1468.)
Dr. Berry found the Brattle Group report lacking in some respects; the
report incorporates assumptions to which he took exception. (Tr. at 1487.)
For example, the report failed to take into account Idaho Power Company's
portion of Sierra's Valmy plant. (Tr. at 1489.) Additional transmission
facilities are needed to eliminate a load pocket. (Tr. at 1492.) The
divestiture of generating assets is a positive step toward achieving
effective competition; the merger should not be approved without
divestiture. (Tr. at 1495.)
8. Upon questioning by the Commission, Dr. Berry confirmed that he has tried
to weigh the loss of a potential competitor in the two Joint Applicants'
service territories against the potential increase of new competitors as a
result of the divestiture of generation assets. (Tr. at 1496-97.) The
evaluation was difficult to do because the number of new competitors is
unknown. (Tr. at 1497.) The time frame in which this proposed merger was
filed presents problems because Nevada is presently in the process of
establishing the rules for a restructured electric industry. He agreed that
the joint application should have included an analysis of how the merger
would affect competition once the merger is consummated. (Tr. at 1497-98.)
Absent this merger, Dr. Berry would expect NPC and Sierra Pacific to be the

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strongest competitors for retail energy services in each other's service
territory. (Tr. at 1505.)
9. Staff called Dr. Larry Blank, Manager of Regulatory Policy and Market
Analysis, as its next witness. His prepared direct testimony was marked
Exhibit 31. He made some corrections to this testimony when he took the
witness stand. (Tr. at 1510.) On cross-examination, Dr. Blank agreed that
finding that an outcome is in the public interest requires that there be
certainty about such an outcome. Certainty about the price at which a
commodity will be provided, either via regulation or competitive forces, is
desirable. Certainty that the merged company will be financially viable is
an important factor. (Tr. at 1512, 1525.) The recourse aggregation tariff
proposed by the Brattle Group report provides an inefficient means to check
market power; the least efficient means of checking market power will cost
customers the greatest amount of money. (Tr. at 1523-24.) He believes it is
appropriate that this merger and divestiture be conditioned on
implementation of ways by which market power can be checked. (Tr. at 1524.)
Dr. Blank recommends that the Commission require the Joint Applicants to
file a complete divestiture plan which would be subject to the Commission's
approval. If the Commission were to approve the joint application as filed,
with respect to divestiture, it would only be broadly endorsing the concept
of divestiture. (Tr. at 1550.) Ideally, divestiture should be completed
immediately prior to the onset of retail competition. (Tr. at 1579.)
10. Upon questioning by the Commission, Dr. Blank explained that he recommends
that final consummation of the merger not be approved until the divestiture
plan itself has been approved. Alternatively, final approval of the merger
could be withheld until after the auction of the generating assets has been
completed. Dr. Blank prefers the former approach. (Tr. at 1588-89.) Staff
does not recommend any approval of the merger without divestiture. (Tr. at
1589.) Dr. Blank recommends that FERC approval of a wholesale generation
tariff be obtained before the auction of the generating assets takes place.
(Tr. at 1590.) He stated that he is not asking the Commission to
micromanage the divestiture process prospectively. (Tr. at 1592.) He agreed
that the Commission should also require that an ISA and a generation
aggregation tariff be approved by the FERC in forms consistent with
Nevada's plans for retail competition. (Tr. at 1595-96.) Certain ratemaking
functions, such as the deferred process, need to be eliminated before the
onset of retail competition, because they are inconsistent with the concept
of competition. (Tr. at 1598.)
11. Staff called Ms. Sharon Thomas, Director of Regulatory Operations, as its
next witness. Her prepared direct testimony was marked Exhibit 41. On
cross-examination, Ms. Thomas testified that some of the power supply
contracts which the Joint Applicants presently have extend beyond the date
for the onset of retail competition. (Tr. at 1615.) Newmont's contract with
Sierra provides for termination charges to be paid by Newmont if it cancels
its contract for reasons other than force majeure. (Tr. at 1617.) Despite
the terms of the contracts themselves, Ms. Thomas believes that certain
accommodations might be possible, either through a "fresh look" at the
contracts, as is being contemplated in the telecommunications industry, or
through the possibility that the utilities may actually be unable to
perform under the contracts. (Tr. at 1619-20.) The Commission has
discretion to decide whether a utility can provide aggregation service via
an affiliate. (Tr. at 1620.) Although there is uncertainty with respect to
whether the utilities will be in a position to provide service to customers
such as the mines, Ms. Thomas does not believe such customers will be left
without service. (Tr. at 1621-22.) The joint application is silent with
respect to how the utilities will meet the obligations of their contracts
with certain customers. (Tr. at 1625.) Staff believes the obligations
incurred in the QF contracts should be addressed in the context of stranded
costs. (Tr. at 1625.) Staff seeks Commission approval of any divestiture
plan in part to minimize market power, to ensure that the auction process
is an open one, and to ensure continuing operational responsibility with

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respect to the generating units. (Tr. at 1633-34.) Ms. Thomas believes that
the Commission will be obligated to determine a recovery mechanism for any
amount of dollars which are not above book value which the Joint Applicants
may realize from the sale of generating assets, if the companies actually
follow a divestiture process approved by the Commission. (Tr. at 1636.)
Approval of the process cannot guarantee that the process will be
implemented properly; the companies will still bear some risk if they fail
to follow the prescribed process. (Tr. at 1636-37.) The Commission has to
be concerned about service to all customers, including large customers such
as the mines, because of the latter's import to the economy of the state.
(Tr. at 1637-38.) There will not be effective competition in the state on
the same day that divestiture is completed if divestiture is completed as
presently envisioned by the Joint Applicants, at the end of 1999. (Tr. at
1639.) Until effective competition is achieved, it is necessary to impose
regulatory constraints on prices. (Tr. at 1640.) Ms. Thomas agreed that the
Commission should resolve, in the course of the decision to be made on this
merger, how the utilities will meet their duties to serve between now and
the time that effective competition is in place. (Tr. at 1640-41.) Ms.
Thomas believes the Joint Applicants have created some problems and
uncertainties for themselves by filing for approval of this merger in the
time frame in which they did, i.e., before many issues which relate to
restructuring have been resolved. (Tr. at 1650-51.) She is troubled that
the utilities have expressed an inability to decide whether they want to
function as aggregators, but were able to decide to merge. (Tr. at 1651.)
Staff does not recommend approval of this merger under all the terms set
out by the Joint Applicants; Staff does recommend approval if all the
conditions it has identified are attached to approval. (Tr. at 1654.) Ms.
Thomas understands that the Joint Applicants have expressed an intention to
honor all contracts they presently have; she is concerned about exactly how
the Joint Applicants will in fact achieve their stated intentions. (Tr. at
1669.) A decision by this Commission which would require that divestiture
precede consummation of the merger would clearly affect the companies'
abilities to honor their contracts. (Tr. at 1670.) The lack of business
plans from the Joint Applicants makes it difficult to assess the effect of
this merger on competition. Staff is unable to determine how particular
markets will be affected. (Tr. at 1684-86.) As other Staff witnesses has
stated, Ms. Thomas recommends that final approval of the merger be made
contingent on final approval of the divestiture plan. (Tr. at 1692.) She
considers the benefit expressed by the Joint Applicants, namely the
continuation of local corporate management, a hollow benefit, because such
continuity could be obtained without any merger. There is no showing that
either company is subject to takeover by an out-of-state entity, that
either company will not move its headquarters, or that the merged entity
might prove more attractive to an out-of-state company. (Tr. at 1694-95.)
NPC has stated its intent to cut its dividend, which Staff supports,
regardless of the merger. Therefore, the dividend reduction cannot really
be viewed as a benefit of the merger. (Tr. at 1697-98.)
12. On redirect examination, Ms. Thomas confirmed that she does not believe the
merger will enhance competition; it may in fact deter retail competition.
(Tr. at 1700-01.) Assuming that sales of wholesale generation to
alternative sellers is regulated in terms of price, and an appropriate
generation aggregation tariff is in place, and that other protections are
in place, Staff recommends that there be no regulation of retail prices
once competition begins. (Tr. at 1704-05.) On recross-examination, Ms.
Thomas explained that Staff does not recommend that markets be opened free
of regulation before it is certain that competition to constrain price
increases exists. (Tr. at 1708.) The insufficiency of the transmission
systems contributes to the load pocket problems. (Tr. at 1710.) Building
new generation in the north would help alleviate the problem. (Tr. at
1711.) She agreed that certain issues will be clearer once the Joint
Applicants have filed applications for authority to provide potentially

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competitive services via affiliates; the applications will reveal which
lines of business the affiliates want to be in. (Tr. at 1716.) The
unavailability of such information in this proceeding lends it a degree of
uncertainty. (Tr. at 1716.)

Nevada Independent Energy Coalition
1. NIEC presented Mr. Donald Schoenbeck, a member of Regulatory and
Cogeneration Services, Inc., a utility consulting firm. His prepared direct
testimony was marked Exhibit 25. On cross-examination, he testified about
how other jurisdictions have addressed the treatment of QF contracts.
California has indicated that the contracts are to be honored for their
full terms and their costs to be recovered from ratepayers. Maryland is
considering similar treatment. (Tr. at 884-85.) Sale of these contracts has
been proposed in some states in the northeast. The contracts are actually
transferred to the purchasing party. (Tr. at 885.) Mr. Schoenbeck knows of
three auctions taking place at this time in which the QF contracts are part
of the bundle for which bidders are bidding along with assets owned by the
utilities. (Tr. at 885-86.) He agreed that due to retail competition,
consumers may no longer be indirectly obligated to buy the output of
cogenerators. (Tr. at 887.) NIEC proposes that various conditions be
imposed before any of its contracts are assigned. The merged company should
be required to honor the contracts. Any above-market costs associated with
these contracts should be collected from ratepayers as they have been in
the past, except that collection should be accomplished through a separate
charge for the delivery component of the distribution charge. (Tr. at 890,
896.) Mr. Schoenbeck cited NRS 704.320 as authority for the Commission to
require ratepayers to pay the costs associated with QF contracts through
the lives of the contracts. (Tr. at 910.) NIEC opposes the merger unless
its contracts are honored and it receives assurance that costs will be
recovered through rates. (Tr. at 923, 951-52.) He admitted these contracts
are above market at this time. (Tr. at 924-25.) He agreed that a fair
interpretation of NRS 704.983(1)(b) might require netting assets or
obligations which are above market with those that are below market. (Tr.
at 928.) He agreed that certain customers will cease to buy generation from
NPC in the new environment. Even these customers should have to pay the
costs of the QF contracts if they take delivery services from NPC,
according to Mr. Schoenbeck. (Tr. at 943.) He confirmed that the costs of
his contracts should be recovered through a distribution charge. (Tr. at
969.) Most of these contracts expire in 2023. (Tr. at 972.) NIEC sells all
its output to NPC. (Tr. at 975.) Mr. Schoenbeck understands that the Joint
Applicants's position is that the merger has very little effect on the QF
contracts. (Tr. at 985, 987.) He understands that NPC wants to assign the
QF contracts to the newly-formed Nevada Power Co. (Tr. at 987.) NIEC wants
assurance from the Commission that their contracts will be honored. (Tr. at
990-91.) He agreed that NPC is committed to honoring the contracts, but is
concerned that such a commitment might become meaningless if the
contracting party lacks the necessary financial means. (Tr. at 992.) Mr.
Schoenbeck agreed that Nevada Power Company will no longer be able to hold
on to generation assets, but believes there is still a question as to
whether it will be able to maintain purchased power obligations. (Tr. at
994.)
2. Upon questioning by the Commission, Mr. Schoenbeck explained that he
understands Portland General Electric/Enron is seeking to divest all its
generating assets, which includes some purchased power and/or QF contracts.
(Tr. at 1000-001.) He has not testified in any proceeding which
contemplated auctions involving cogeneration or QF contracts, but is
familiar with at least three such auctions. (Tr. at 1001.) The QFs' consent
to have their contracts assigned was obtained by the vertically integrated
electric utilities in these situations. (Tr. at 1002.) Mr. Schoenbeck
described this joint application as problematic in that restructuring
raises the possibility that the revenue stream which the QFs have counted

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on may be adversely affected. (Tr. at 1003.) The process recommended by Mr.
Garrett for the Mirage/MGM (whereby actual revenue requirements would be
established upon the filing by the utilities of a rate case, with
unbundling by functionalizing and allocating cost of service as part of the
decision in the rate case, followed by divestiture of generating assets)
would alleviate some of Mr. Schoenbeck's concerns relative to the viability
of the QF contracts. (Tr. at 1004-05.) He admitted that NRS 704.320 was
enacted long before the Public Utility Regulatory Policies Act ("PURPA")
and therefore was not enacted in anticipation of PURPA. (Tr. at 1010.) NRS
704.320 refers to "surplus" electric current; Mr. Schoenbeck admitted that
the output from NIEC's facilities is not surplus. (Tr. at 1011-12.) NIEC is
concerned about whether there will ultimately be a backer to the contracts
it has with NPC. (Tr. at 1012.)

UCA
1. Dr. Richard Rosen, Senior Research Director at Tellus Institute, testified
for the UCA. His prepared direct testimony was marked Exhibit 32. He made
some corrections and additions to this testimony when he took the witness
stand. (Tr. at 1258-64.) Dr. Rosen testified that the correct economic test
for whether a transmission and distribution company should make new
investments is still the traditional test of integrated resource planning,
except now the test should utilize the market price for generation when
analyzing the trade-off between investing in new transmission versus new
generation. (Exhibit 32, p. 8.) Horizontal market power is not likely to be
a major problem if the generating units are bundled into the seven groups
presented by CSFB to the NPC Board of Directors on June 11, 1998. The full
transmission import capability into both load pockets is rarely fully
utilized, contrary to the assumptions made in the Brattle Group's report.
(Exhibit 32, p. 9-10.) On cross-examination, Dr. Rosen explained that he is
not recommending the Commission adopt the stranded cost figures or
methodology included in his testimony; they were offered to provide a sense
of the potential value of the plants to be divested. (Tr. at 1264-65.) Any
approval of investment in transmission facilities should be made in a
resource planning proceeding, not as part of this merger. (Tr. at 1266-67.)
He considers the proposal for a separate wires charge for QF contracts
unnecessary and premature. (Tr. at 1279.) A wires charge should be
determined later once a total net stranded cost has been computed. (Tr. at
1280.) Dr. Rosen characterized the Joint Applicants' intentions to continue
to invest in transmission and distribution facilities in Nevada as
confusing. (Tr. at 1326.)
2. On redirect examination, Dr. Rosen testified that any income from the sale
of generating assets should be used to offset rates and be recovered as
stranded costs if net stranded costs are negative. If the net of all
stranded costs turns out to be positive, all income should be used to
mitigate positive stranded costs. (Tr. at 1340.) On recross-examination, he
explained that "positive stranded costs" occur when net book value exceeds
market value; "negative stranded costs" are the reverse. (Tr. at 1353.)
3. Upon questioning by the Commission, Dr. Rosen agreed that stranded costs
are a way that people will have to pay in the future for sins of the past
and are therefore unavoidable. (Tr. at 1366.) The wires charge proposed by
some parties to this proceeding could well be authorized under the "direct
and unavoidable recovery mechanism" found in NRS 704.983. (Tr. at 1367.)

Phase II - Effect of the Merger on Costs, Rates, and Quality of Service
1. Mr. Niggli also appeared as a witness for the Joint Applicants in Phase II.
On cross-examination of the portion of his direct testimony which addressed
this phase, he explained that customers are guaranteed long-term rate
stability for regulated services because the Joint Applicants have proposed
a freeze on current rates until 2002. Mr. Niggli also believes the cost
savings to be realized from the merger contribute to rate stability. (Tr.
at 1733-34.) He realizes that the acquisition premium, or goodwill,

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involves amortizing $11 million per year. (Tr. at 1754.) Mr. Niggli expects
savings from the merger to exceed the amount of goodwill. (Tr. at 1754-55.)
The Joint Applicants have proposed that ratepayers receive earnings in
excess of a return on equity of 12 percent; Mr. Niggli was not surprised
that no analysis of the current costs of equity capital was conducted
before this figure of 12 percent was chosen. Twelve percent is high, but he
hopes to exceed it and have something to share with ratepayers. (Tr. at
1765.) NPC's current rates are the result of a negotiated settlement. Mr.
Niggli believes that such rates can perhaps be unbundled without a cost of
service study. (Tr. at 1770-71.) He does not believe ratepayers should be
entitled to any negative stranded costs because they will benefit from the
merger and the divestiture plan. He does not believe ratepayers need to
know the magnitude of stranded costs in order to ascertain whether they are
actually benefitting. (Tr. at 1771.) The utilities would not consider
divesting their generation assets unless they were merging. The merger
affords them the opportunity to use the proceeds from the sale to write off
stranded costs and to implement a sharing mechanism. (Tr. at 1772-73.) Mr.
Niggli is aware that various parties recommend placing the acquisition
adjustment below the line; he considers such a measure unfair because
benefits would flow to ratepayers while costs would flow to the companies.
(Tr. at 1778.) If such a condition were adopted by the Commission, the
Joint Applicants would decide whether to go through with the merger; Mr.
Niggli characterized the condition as a potential "deal-breaker." (Tr. at
1778.) He understands none of the provisions of Assembly Bill 366 (NRS
704.965 to 704.990, inclusive, as well as other provisions of Chapter 704
of NRS) authorizes the abrogation of any contracts the utilities currently
hold. While the provisions of NRS 704.986 do sound much like the elements
of a rate case, Mr. Niggli understands this statute to require perhaps only
unbundling of rates. (Tr. at 1791.)
2. Mr. Malquist also testified in Phase II. On cross-examination, he testified
that the companies believe the merger will enhance quality of service, in
part because the best practices of both companies can be combined. (Tr. at
1802-03.) He admitted that the Joint Applicants have not proposed any
standards or goals for quality of service. (Tr. at 1804.) The transition
teams which will evaluate best practices are not formulated yet. (Tr. at
1804.) Mr. Malquist agreed that it is much easier to identify the costs
associated with a merger than it is to identify benefits. (Tr. at 1813.) He
confirmed that if the Commission were to condition approval of the merger
on all the conditions recommended by Staff or the UCA, he would recommend
to his Board of Directors that the merger be abandoned. (Tr. at 1815-16,
1864.) He confirmed that he does not believe proceeds from the gain on sale
should be used to offset above-market stranded costs from QF contracts,
even though they represent a type of stranded cost. The utilities did not
have the same degree of responsibility in incurring these costs as they did
for capital investments. (Tr. at 1822-23.) He recognizes that some
consultants retained by Sierra have viewed the costs of QF contracts as
stranded costs like any other stranded costs. (Tr. at 1823.) Mr. Malquist
will relocate to Las Vegas some time after assuming the position of
President and Chief Executive Officer of the merged company. He plans to
travel between northern and southern Nevada a great deal in order to run
the two subsidiaries. The costs of this travel are not reflected in the
joint application because the Joint Applicants do not consider them costs
of the merger itself; they are considered a cost of running the business
prospectively for which cost recovery will be sought in the future. (Tr. at
1823-24.)
3. Upon questioning by the Commission, Mr. Malquist testified that in terms of
evaluating the best practices of the companies, he has determined that
NPC's materials management and procurement area may be superior to
Sierra's. (Tr. at 1858.) Sierra's budgeting process may be better than
NPC's. (Tr. at 1859.) Mr. Malquist does not believe NRS 704.986 describes a
rate case; it might describe a process for unbundling previously-set rates.

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(Tr. at 1869-73.) He cannot assure anyone that the merged company will not
be taken over by some out-of-state company later on. (Tr. at 1887-88.)
Current rates for the companies are not based on current costs. (Tr. at
1897.)
4. Mr. Mark Ruelle, Senior Vice President, Chief Financial Officer, and
Treasurer for Sierra Pacific Resources and Sierra Pacific Power Company,
testified next for the Joint Applicants in Phase II. His prepared direct
testimony was marked Exhibit 53. On cross-examination, he testified that
the $445 million in goodwill does not reflect investment in hard assets,
but it does reflect investment in the company in actual dollars. (Tr. at
1899.) Access to the books and records of Sierra Pacific Resources, the
holding company currently for Sierra Pacific Power Company and, following
the merger, also for NPC, has been an issue in the past. Mr. Ruelle stated
that whatever access Staff or the UCA has had in the past, it will continue
to have. (Tr. at 1907.)
5. Upon questioning by the Commission, Mr. Ruelle confirmed that he has not
yet determined whether various systems of NPC and Sierra should be joined
or integrated. (Tr. at 2009.)
6. Mr. Richard Schmalz, Director of Treasury for NPC, testified next. His
prepared direct testimony was marked Exhibit 57. On cross-examination, he
agreed that the cost of issuing new debt has declined over the past few
years. (Tr. at 2021.) NPC has consulted with its bond counsel about the
steps necessary to preserve its tax-exempt bond status in light of the
impending merger. (Tr. at 2026.) NPC will need a final opinion from bond
counsel before the merger in consummated. (Exhibit 58; Tr. at 2028-29.) NPC
is willing to hold ratepayers harmless for any increased net costs from the
loss of tax-exempt status which results from the merger. NPC is not willing
to hold them harmless for any increased costs which result from any other
event. (Exhibit 59; Tr. at 2033.)
7. Ms. Mary Simmons, Controller for Sierra, testified next. Her prepared
direct testimony was marked Exhibit 60. On cross-examination, she testified
she believes that both NPC and Sierra are expensing the costs of the
customer information systems transition team. (Tr. at 2043.) Upon
questioning by the Commission, Ms. Simmons stated that she does not object
to submitting merger service agreements to ensure that the cost allocation
methodology for services other than electric services are appropriate, as
long as such an agreement is to concern only services not already covered
by the affiiliate regulation. Ms. Simmons recognizes the difference between
the provision of services declared potentially competitive and the
provision of those services which Sierra's Simple Choice program offers.
(Tr. at 2052.)
8. Mr. Matt Davis also testified in Phase II. On cross-examination, he
admitted that the joint application does not contain any objectives or
standards regarding quality of service, although he believes quality will
not be adversely affected or might improve. (Tr. at 2055.) While he does
not object to the recommendation which Staff has made in this area, he is
not sure data is available at this time in order to provide a benchmark
from which comparisons will be made in the future and is concerned about
the resources that will be necessary to monitor service and reliability
prospectively. (Tr. at 2056.)

Southern Nevada Water Authority
1. SNWA presented Dr. Dennis Peseau, President of Utility Resources, Inc., a
utility consulting firm, as its only witness. His prepared direct testimony
was marked Exhibit 61. He made some corrections to and partially clarified
this testimony when he took the witness stand. (Tr. at 2062-65.) On
cross-examination, Dr. Peseau testified that, as submitted by the Joint
Applicants, the proposed merger is not in the interest of ratepayers. (Tr.
at 2066-67, 2082-84.) He recommends that ratepayers receive all gain
realized by the sale of generating assets, offset by their obligation to
pay stranded costs. While shareholders certainly assume risk, they have

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been compensated for this risk by a fair rate of return. (Tr. at 2068-69.)
He also recommends that NPC file a general rate case in order to determine
what rates should be. (Tr. at 2078.) He understands that the Joint
Applicants propose collecting the acquisition adjustment from savings
realized from the merger, but he opposes any recovery. (Tr. at 2083-84.)
Any gain realized from the sale of generating assets should be used to
offset any above-market obligations associated with the QF contracts. (Tr.
at 2093-94.) Upon questioning by the Commission, Dr. Peseau stated he
recommends a prohibition on any commingling of divestiture proceeds between
NPC and Sierra. (Tr. at 2120.) While Dr. Peseau is not in favor of an
earnings sharing mechanism or a rate freeze, but if these are imposed, he
recommends an earnings dead band, which involves recovery of amounts where
the utility is not earning a fair rate of return, reduced by some amount of
basis points. (Tr. at 2122-23.) His major criticism of an earnings sharing
mechanism stems from the fact that they are based on a target rate of
return, which changes with capital markets. (Tr. at 2125-26.)

Utility Consumers Advocate
1. Mr. Michael Brosch of Utilitech, Inc. in Kansas City testified for the UCA.
His prepared direct testimony was marked Exhibit 47. On cross-examination,
he clarified that he does not believe there should be any explicit
authority granted for recovery of goodwill, because such recovery is an
improper departure from cost-based regulation, unfairly burdens ratepayers
with market gains already retained by shareholders, significantly dilutes
any potential savings otherwise realized from the merger, and can be
recovered through other benefits from the merger which shareholders are
expected to retain. (Exhibit 47; Tr. at 2131-33.) While he is aware that a
number of jurisdictions have allowed recovery of goodwill, Mr. Brosch
considers the issues surrounding goodwill case-specific and did not place
any great importance on what other commissions have done. (Tr. at 2146.)
Mr. Brosch considers the merger savings speculative because they are based
on a lot of assumptions. (Tr. at 2177.) In terms of any savings in labor
which might result from the merger, he cautions against taking any budgeted
but unfilled positions into account because doing so is essentially adding
someone to the list of employees, removing him, and calling the removal a
savings. (Tr. at 2190.) Mr. Brosch does not believe merger savings can
every really be measured, because the benchmark of the two unmerged
utilities is lost. (Tr. at 2200-01.) Upon questioning by the Commission, he
testified that goodwill should only be recovered in extraordinary cases.
Accounting for goodwill below the line need not mean denying all
opportunities to recover other benefits which would offset the charge to
income. (Tr. at 2251.)
2. The UCA called Mr. David Parcell of Technical Associates, Inc. of Virginia
next. His prepared direct testimony was marked Exhibit 65. On
cross-examination, Mr. Parcell testified that the 12 percent sharing
mechanism under which Sierra operates now was based on facts which have
changed since it was set. It is inappropriate to automatically apply
Sierra's return on equity to NPC. Sierra's 12 percent return on equity is
being used for a purpose other than the one for which it was established.
(Exhibit 65; Tr. at 2260, 2305, 2313.) On redirect examination, he
explained that he recommends a cost of equity on the low range of
approximately ten percent, whereas he recommended ten to 11 percent in
Westpac's water rate case, because the portion of the remaining business
after generating assets are sold presents less risk. (Tr. at 2294-95.) On
recross-examination, he stated that the Joint Applicants plan to finalize
divestiture commensurate with the onset of retail competition. (Tr. at
2297.) Upon questioning by the Commission, Mr. Parcell agreed that it is
probably inappropriate to apply rates which pertained to vertically
integrated electric utilities to a transmission and distribution company.
The Joint Applicants do not propose resetting rates for another three
years. (Tr. at 2311-12.)

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Mt. Wheeler/Deseret
1. Mr. Curtis Winterfeld of Deseret testified for Mt. Wheeler and Deseret. His
prepared direct testimony was marked Exhibit 67. He made some corrections
to this testimony when he took the witness stand. (Tr. at 2316.) On
cross-examination, Mr. Winterfeld explained that Mt. Wheeler and Deseret
are concerned about quality of service in rural areas; the former is
interested in acquiring some of the rural territory presently served by
Sierra because Mt. Wheeler believes it can serve in a more cost-effective
manner. (Exhibit 67; Tr. at 2324.) Upon questioning by the Commission, he
confirmed that as proposed, he does not consider the merger in the public
interest. (Tr. at 2342.) He looks upon the recommendations advanced by
Staff and the UCA as a "start" and added that more detail is needed to
implement the recommendations made. (Tr. at 2343.)

Regulatory Operations Staff
1. Mr. John Candelaria, Electrical Engineer, testified for Staff in Phase II.
His prepared direct testimony was marked Exhibit 68. On cross-examination,
Mr. Candelaria agreed that the purpose of his testimony is to propose
various indices that will apply prospectively to the Joint Applicants after
the merger. (Tr. at 2353.) He is willing to discuss with the companies
which of his proposed indices are the most important. (Tr. at 2354.) NPC
does not presently have a system in place to calculate any of the indices
Mr. Candelaria has proposed; the system is scheduled for completion late in
1999. (Tr. at 2361.) He does not consider the information which NPC now
provides to Staff or to the Commission adequate to serve as a benchmark
from which levels of quality can be measured after the merger. (Tr. at
2363.) Although the information currently provided gives the number of
outages, it does not identify which circuits were involved. (Tr. at 2364.)
Upon questioning by the Commission, Mr. Candelaria agreed that it has been
difficult to obtain information about NPC's distribution system. (Tr. at
2367.) Because the two systems are different, it is important to establish
separate benchmarks for NPC and Sierra and to compare future results only
to the respective benchmarks for one utility. (Tr. at 2369.) NPC does not
take issue with the benchmark standards for reliability which Mr.
Candelaria has proposed. (Tr. at 2372.) In cooperation with the Joint
Applicants, benchmarks can be established in 60 days. (Tr. at 2372.)
2. Mr. Richard Hackman, Manager of the Consumer Complaint Resolution Division,
testified next for Staff. His prepared direct testimony was marked Exhibit
69. On cross-examination, he agreed that the level of customer service
presently provided by NPC and Sierra is good. (Tr. at 2379.) The economies
which the Joint Applicants hope to gain from the merger, through reduction
in staffing, might threaten areas such as customer service. Mr. Hackman is
concerned about the possibility of a reduction in the level of customer
service. (Tr. at 2386-87, 2425.) NPC instituted some downsizing in
approximately 1994 as part of a program known as NP 2000. (Tr. at 2387-88.)
Sierra has also downsized over the past ten years. Mr. Hackman admitted he
has not witnessed a measurable decline in the level of customer service in
these time frames. (Tr. at 2388.) With respect to NPC, there have been
problems in the degree of timeliness in which NPC responds to complaints
which Mr. Hackman's division relays to NPC. (Tr. at 2388.) This problem has
not been corrected. (Tr. at 2388-89.) He recommends that the Joint
Applicants be prohibited from reducing customer service staffing to the
degree proposed (64 positions for the two utilities) at least until the
onset of retail competition. (Tr. at 2401.) Staff has not received
definitive answers from Sierra with respect to whether the latter plans on
closing any of its branch offices. (Tr. at 2403-04.) On redirect
examination, Mr. Hackman stated that if the Joint Applicants do eliminate
64 customer service positions, it seems unlikely that response levels would
improve. (Tr. at 2414.) He wants the companies to maintain their current
levels of customer service. (Tr. at 2415.) Upon questioning by the
Commission, Mr. Hackman testified that Staff has inquired of the Joint

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Applicants whether they plan on consolidating certain facilities and
functions; the responses to date have been vague except to say that
decisions have not been made. (Tr. at 2422-23.) He clarified that any
standards established for customer service should apply to all companies
which offer the service, not only the Joint Applicants. (Tr. at 2423-24.)
The benchmarks against which NPC and Sierra will be judged in the future,
though, have to come from these companies' past histories of service
levels. (Tr. at 2424.)
3. Mr. Lew DeWeese, Senior Financial Analyst, also testified for Staff in
Phase II. His prepared direct testimony was marked Exhibit 24. There was no
cross-examination of his testimony.
4. Mr. Paul Anderson, Senior Financial Analyst, testified next. His prepared
direct testimony was marked Exhibits 70, 71, and 72. He explained the
corrections reflected on Exhibits 71 and 72 when he took the witness stand.
(Tr. at 2433-35.) On cross-examination, Mr. Anderson testified that because
shareholders will reap any benefits of the merger, they should bear the
costs of goodwill. (Tr. at 2436.) He believes shareholders are expected to
benefit from the merger because stock price is expected to increase. (Tr.
at 2437-38.) The various news articles published about this hearing have
affected the stock prices of both companies. (Tr. at 2444.) On redirect
examination, Mr. Anderson stated that NPC's stock price rose $25 million on
the day he testified; he does not correlate this increase to the
recommendations he has offered. (Tr. at 2447.) On recross-examination, he
agreed that the information in the press about this merger does affect
decisions which shareholders make. (Tr. at 2451.) Upon questioning by the
Commission, Mr. Anderson confirmed that the Joint Applicants' proposal
anticipates the repurchase of some stock at a set price, which is above
prices which prevailed at the time of this hearing in late November 1998.
Shareholders certainly stand to benefit from this repurchase. (Tr. at
2452.)
5. Mr. Michael Greedy, Financial Analyst, appeared next for Staff. His
prepared direct testimony was marked Exhibit 33. There was no
cross-examination of his testimony.
6. Dr. Larry Blank, Manager of Regulatory Policy and Market Analysis,
testified next for Staff in Phase II. His prepared direct testimony was
previously marked Exhibit 31. On cross-examination, Dr. Blank testified
that any savings which result from the merger, which constitute a cash flow
item, should be considered separately from goodwill, which does not affect
cash flow. (Tr. at 2464-66.) Upon questioning by the Commission, he stated
he does not support a proposition to apply any merger savings which may
materialize in the future to goodwill, in part because tracking savings
which relate directly to the merger, rather than to other factors such as
restructuring, is difficult. (Tr. at 2482-83.) Because he considers savings
from the merger and goodwill unrelated and mutually exclusive, Dr. Blank
does not recommend allowing shareholders to retain savings up to the level
of goodwill or even at some other level. (Tr. at 2486-88.) He did state,
though, that providing an incentive for the utilities to actually achieve
expected savings is not necessarily a bad idea. (Tr. at 2490.) The joint
application does not contain any analysis of how the merged companies will
participate in the market for potentially competitive services. (Tr. at
2497.)

Joint Applicants
1. Mr. Steven Oldham also testified in Phase II. His prepared direct testimony
was previously marked Exhibit 11; revisions were marked Exhibits 73 and 74.
On cross-examination, Mr. Oldham testified that the cost of common equity
and cost of debt have both declined since they were last set. (Tr. at
2505-06.) While he agreed that cost of service should be reviewed in the
context of the filing required by NRS 704.986, he does not support setting
new rates on the basis of cost of service. (Tr. at 2508-09.) The Joint
Applicants propose a sharing mechanism for earnings above a return on

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common equity of 12 percent, even if the cost of common equity is
determined to be lower than 12 percent. (Tr. at 2510-11.) The hold-harmless
mechanism proposed by the Joint Applicants was designed to not adversely
affect ratepayers, i.e., costs which flow through should be fully offset by
benefits. (Tr. at 2527.) He clarified that if future savings prove to be
below the cost of merging, the companies will assume responsibility for the
shortfall. (Tr. at 2532.) Sierra intends to continue the sharing mechanism
it currently has in place. (Tr. at 2550.) Mr. Oldham considers the proposed
sharing mechanism the best way to make the companies efficient and the best
way to realize savings. Some form of incentive ratemaking should be put in
place forever. (Tr. at 2654.) Goodwill should be allocated to investment.
If meters are actually transferred to an affiliate, goodwill should be
allocated to the affiliate. (Tr. at 2655.) Upon questioning by the
Commission, Mr. Oldham stated that some of the savings in labor which the
Joint Applicants expect to achieve from the merger are attributable to
attrition. (Tr. at 2658-59.) If the Commission were to reject the rate plan
and hold harmless agreement proposed in this joint application, such a
decision would not necessarily be a "deal breaker," as long the companies
are not precluded from collecting costs through rate cases. (Tr. at
2659-60.) Sierra achieved some savings as a result of its attempt to merge
with Washington Water Power, even though the merger was not consummated.
(Tr. at 2661-64.) He agreed that a utility should strive to become more
efficient whether it is in the process of merging or not, but denied that
it's a huge issue for the Commission to try to separate efficiencies which
come about from a merger from those that might be achieved anyway. (Tr. at
2664.) He admitted that tracking costs to demonstrate the existence of
actual savings to apply against the cost of the transaction is difficult.
(Tr. at 2666.) The Joint Applicants are willing to be held to the total
savings they have estimated. (Tr. at 2670.)

Staff
1. Ms. Sharon Thomas also testified for Staff in Phase II. Her prepared direct
testimony was previously marked Exhibit 41. On cross-examination, Ms.
Thomas testified that Staff has attempted, in the course of reviewing this
joint application and formulating its recommendations, to balance the
interests of both ratepayers and shareholders. For instance, with respect
to the gain on sale, Staff supports the proposal to return to investors
money they have put into plant. Any gain realized should first be used to
offset stranded costs. Amounts over what is needed to offset can be split
between ratepayers and shareholders. (Tr. at 2691-92.)

Joint Applicants' Rebuttal - Phase I
1. The Joint Applicants called Dr. Robert Fox-Penner as their first rebuttal
witness for Phase I. His prepared rebuttal testimony was marked Exhibit 79.
He made some corrections to this testimony when he took the witness stand.
(Tr. at 2710-17.) On cross-examination, Dr. Fox-Penner testified that he
considers the transmission system in the northern part of the state to be
constrained nearly every hour of the year. (Tr. at 2718.) New generation in
the load pocket would enhance competition. (Tr. at 2719.) FERC requires
that an application for approval of a merger include calculations of the
Herfindahl-Hirschman Index ("HHI"). The Joint Applicants' filing with FERC
includes the HHI. The joint application filed with this Commission does
not, but contains what Dr. Fox-Penner considers a more refined model-based
approach which reveals more information. (Tr. at 2736-39.) The HHIs he
prepared for FERC deal only with wholesale markets. (Tr. at 2741.) He
agreed that the Commission should be concerned about market concentration
in retail markets once the markets are opened. (Tr. at 2743.) Policy makers
do sometimes require divestiture as part of approving a merger. (Tr. at
2744.) Divestiture is a useful tool to remove market concentration. (Tr. at
2745.) With respect to the number of bundles of generation which should be
auctioned, Dr. Fox-Penner pointed out that very large economies of scale

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apply to the operation of power plants. Fairly large concentrations of
generation will lower costs to consumers. (Tr. at 2747.) The amount of
transmission import capacity into the load pockets will determine the
degree of competition in the load pockets. (Tr. at 2755.) Transmission
planning is moving away from the context of integrated resource planning
and toward the context of an ISA or ISO. (Tr. at 2758.) Dr. Fox-Penner did
not conduct a sensitivity analysis for new entry into the generation market
aside from one 108-megawatt unit in northern Nevada. (Tr. at 2808-11.) The
Brattle Group analysis does not include Idaho Power Company's share of
Sierra's Valmy plant in the base case scenario, which means the scenario
shows higher demand and a higher potential for market power. This omission
does not alter Dr. Fox-Penner's conclusion that the future owners of
generation in the northern part of the state will potentially be able to
exercise market power, nor does it alter the transitional mitigation
measure he has proposed. (Tr. at 2848-49.)
2. Mr. Richard Schmalz also provided rebuttal testimony for Phases I and II.
His prepared rebuttal testimony was marked Exhibit 81. One addition to this
testimony was made when he took the witness stand. (Tr. at 2853.) On
cross-examination, he stated that it often takes at least a year to obtain
an IRS letter ruling. He admitted that the Company chooses when to submit a
request. The Joint Applicants have not made such a request to date. (Tr. at
2856.) A letter ruling might be invalid if a change in company operations
is made after a request is submitted. (Tr. at 2856-57.) Bond counsel and
tax counsel have recommended against obtaining an IRS letter ruling. (Tr.
at 2858.) If facilities which are moved to competitive affiliates were
funded by tax-exempt bonds, partial refunding of a bond issue or issues
might be required. (Tr. at 2864.) Sharing certain operating personnel might
jeopardize NPC's tax-exempt status. (Tr. at 2865.) In the absence of an IRS
letter ruling, NPC agrees to hold ratepayers harmless for any increased net
costs from any loss of tax-exempt status which results from the merger. Mr.
Schmalz could not say how it will be determined in the future whether such
a loss is attributable to the merger or to some other factor such as
restructuring. (Tr. at 2867.) Staff has recommended that a final opinion of
the trustee be obtained in connection with the release of property from the
indenture. The final opinion would indicate that conditions to release
property specified in the indenture have been satisfied. NPC has been
advised that no such final opinion exists. The trustee has informed NPC it
will not issue such an opinion. NPC believes opinion of its bond counsel is
sufficient. (Tr. at 2871.)
3. Ms. Sally Galati, Vice President of Distribution for NPC, also testified as
a rebuttal witness for Phase II. Her prepared rebuttal testimony was marked
Exhibit 82. There was no cross-examination of this testimony.
4. Ms. Evelyn Hollins, Director of Customer Service, also testified on
rebuttal. Her prepared rebuttal testimony was marked Exhibits 83 and 84. On
cross-examination, Ms. Hollins stated that she is willing to provide the
customer satisfaction surveys which NPC generates. However, she does not
believe that Mr. Hackman's recommendations should be imposed on the Joint
Applicants as a condition for approving the merger. (Tr. at 2890-92.) She
agreed that the Commission should be concerned about the quality of
customer service the merged companies will provide. (Tr. at 2898.) While
the Commission is free to make recommendations about staffing levels, final
decisions in this regard should be up to the management personnel of the
utilities. (Tr. at 2899.) Ms. Hollins did not see the Deloitte & Touche
study which identified positions to be eliminated as a result of the merger
until the week of November 30, 1998, when she testified. (Tr. at 2906.) No
one consulted her on whether the proposed reduction in staff was
reasonable. (Tr. at 2907.) She did not review the joint application or
accompanying direct testimony, so she is unaware of whether the companies
have committed to maintaining or improving customer service and if so, how
they plan to do so. (Tr. at 2909-10.) On redirect examination, Ms. Hollins
testified that NPC did reduce staff with NP 2000, but has since added

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staff. She believes the reductions contemplated by this merger will not
affect customer service. (Tr. at 2930.)
5. Ms. Mary Simmons also provided rebuttal testimony, which was marked
Exhibits 85 and 86. She made one correction to this testimony when she took
the witness stand. (Tr. at 2952.) On cross-examination, Ms. Simmons
characterized the proposals made by Staff witness Mr. Greedy as impractical
or impossible to implement. She found the recommendations confusing because
they involve both complete separation and also contracts for services. (Tr.
at 2956.) She also believes his recommendations partially contradict the
affiliate rule issued by the Commission. She considers it impossible for
each company to set up its own investor relations department. (Tr. at
2957.) Upon questioning by the Commission, Ms. Simmons confirmed that the
merged entities do plan to develop an accounting system, whether it be
using Sierra's current system, using NPC's, using a hybrid, or using a new
system. (Tr. at 2987-88.) The latter two are being considered most
seriously at this point. (Tr. at 2991.)
6. Mr. John McClellan was called as the Joint Applicants' next rebuttal
witness. His prepared rebuttal testimony was marked Exhibits 87, 88, 89,
and 90. He made some changes to this testimony when he took the witness
stand. (Tr. at 2996-98.) As noted above, portions of this testimony was
stricken upon a motion brought by Staff. (Tr. at 3012.)
7. Mr. Oldham testified next as a rebuttal witness for Phases I, II, and III.
His rebuttal testimony was marked Exhibits 91, 92, 93, and 94. On
cross-examination, he clarified that the Joint Applicants propose that
goodwill follow assets so that goodwill which is properly allocable to
transmission, which is jurisdictional to FERC, would not be paid by Nevada
ratepayers in connection with distribution. (Tr. at 3020.) Mr. Oldham was
unaware of which potentially competitive services Sierra wishes to provide
in the competitive market. (Tr. at 3034-35.) He believes Sierra can
continue to provide service to its customers with whom it has contracts
through contracts with other energy suppliers. (Tr. at 3036-37.) An
alternative to forming an affiliate is to provide the services now provided
under contract. (Tr. at 3037.) Mr. Oldham believes the proposed divestiture
will facilitate competition. (Tr. at 3044.) He also believes the costs of
the merger will be more than offset by its benefits and hopes to recoup the
costs from the benefits. (Tr. at 3055-56.) If merger savings are not
realized, costs will still have to be borne by shareholders and possibly by
ratepayers if the Commission were to determine such an approach were
appropriate. (Tr. at 3060-61.) In order to actually realize the savings
anticipated from the merger, the Joint Applicants are committed to filing
rate cases on a "frequent and periodic" basis. (Tr. at 3093-94.) Under the
proposal, NPC is to become a subsidiary of Sierra Pacific Resources. The
Commission does not presently have the same level of jurisdiction over
Sierra Pacific Resources as it does over NPC. (Tr. at 3098-99.) He admitted
that the availability of information from SPPCO or Sierra Pacific Resources
has been an issue over the years, but does not believe this affects the
level of jurisdiction which the Commission has over SPPCO now. Since both
SPPCO and NPC will be subsidiaries, Mr. Oldham believes the Commission will
have the same degree of jurisdiction over NPC after the merger that it now
has over SPPCO. (Tr. at 3099.) Upon questioning by the Commission, he
testified that in the northern part of the state, if the generators to be
sold are not physically relocated, it will be very difficult most hours of
the year to sell their output anywhere other than where it is now sold.
This limitation is less problematic in the southern portion of Nevada. (Tr.
at 3102.) Mr. Oldham believes this merger facilitates restructuring and
allows divestiture which will not harm shareholders. It is important to the
Joint Applicants that the merger precede divestiture. (Tr. at 3121.)
Although the Joint Applicants have not decided which potentially
competitive services they wish to offer, Mr. Oldham expects transmission
and distribution to bring in the majority of revenues. (Tr. at 3122.)

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COMMISSION DECISION

Overview

The proposed merger put forth by the Joint Applicants, submitted at the same
time that the Commission is carrying out the Legislature's directive to bring
about retail competition in the electric markets in Nevada by December 31, 1999,
presents questions unprecedented in their complexity, import and quantity for
the State of Nevada. The Commission has the responsibility, pursuant to NRS
704.329, to assure that the merger is in the public interest, and that the
components of the proposed transaction (such as generation divestiture and the
development of an independent system administrator), which will have profound
effects on the functioning of the market, will not impede the Commission's
efforts to implement the legislative directives. As a result of the combination
of issues presently before the Commission, the Commission's review of the
proposed merger could not go forward ignoring what is to be, but rather must
consider whether the proposed merger is compatible with the competitive markets
envisioned by the Legislature.

To accomplish its statutory tasks, the Commission divided its review of the
proposed merger into three broad phases, each composed of specific subject
areas. Phase I included a review of the structural features of the proposed
merger (Subject Area I), its effect on competition (Subject Area II) and its
effect on existing contracts (Subject Area V). Phase II included a review of the
effect of the proposed merger on costs and rates (Subject Area III) and its
effect on quality of service (Subject Area VI). Phase III included a review on
the effect of the proposed merger on the Commission's jurisdiction (Subject Area
IV). The Commission's findings and conclusions below are presented in a somewhat
different order so that each portion of the decision builds on what comes
before. The subject areas have therefore been renumbered as follows:

Part I: Effect on Competition

Part II: Implementation of Structural Conditions on the Merger

Part III: Effect on Costs and Rates

Part IV: Effect on Existing Contracts

Part V: Effect on Quality of Service

Part VI: Effect on Commission Jurisdiction

Part VII: Other Authorization Requested

I. Effect on Competition

A. Positions of the Parties

The Joint Applicants state that the merger will not adversely affect competition
for the provision of either wholesale or retail electric service, and in fact,
argue that the merger will have a positive effect on competition for retail
electric service within the State because it will be a catalyst to retail
competition and customer choice. The Joint Applicants argue that the merger will
promote retail competitive markets in Nevada through the combination of the
proposed divestiture of utility-owned generation, investment in additional
high-voltage transmission intertie capacity, and the implementation of must-run
contracts (GAT) and an iISA. (Ex. 11, p. 8) The Joint Applicants assert that
they designed the proposed merger package to reduce transmission constraints and
load pockets which restrict the availability of energy from outside the
respective control areas at certain times. (Ex. 11, p. 8)

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Aviv Goldsmith, testifying for Coastal Power, testified that Coastal is in favor
of divestiture because it goes towards mitigating market power which moves the
region closer to market-based rates. (Tr. at 778) Similarly, Staff witness Dr.
Dan Berry provided testimony that strongly recommended that the Commission deny
the merger in the absence of divestiture. He states that the development of
effectively competitive markets envisioned by the Legislature would be virtually
impossible if Nevada's utilities do not sell their generation plant to multiple
new owners. (Ex. 39, p. 4) Dr. Berry argues that absent divestiture, only if
enough transmission capacity is built to eliminate Nevada's load pockets will
the potential for effective competition, as contemplated by the Legislature, be
realized. (Ex. 39, p. 5)

The merger filing does not specifically address the effect of the merger on
retail service competition, nor have the Joint Applicants identified those
potentially competitive services which they seek to provide. Both Mr. Niggli and
Mr. Malquist testified that the Joint Applicants had not yet decided which
potentially competitive services they would propose to offer. Dr. Berry
testified that the merger would remove one potential competitor in each of the
regional markets in Nevada. (Tr. at 1468.) As explained in Dr. Berry's
testimony, in the absence of a merger, Nevada Power may have formed affiliates
to operate in northern Nevada markets, competing with Sierra Pacific's
affiliates in those markets. Likewise, Sierra Pacific may have formed affiliates
to offer these services in southern Nevada, providing competition for Nevada
Power's affiliates. Furthermore, even if each of the current companies did not
enter the other's markets, Dr. Berry asserted, the threat of entry can act as a
deterrent to the exercise of market power in the absence of large barriers to
entry in any market.

B. Commission Decision

1. Condition of Generation Divestiture

The Commission agrees with Dr. Berry that absent the merger, there is a strong
likelihood that each of the Joint Applicants would have competed in the other's
territory or at least represented a credible entry threat that could have
disciplined the incumbent to price competitively. Given that each utility would
face competition in its own service territory from new competitors authorized by
the Legislature to sell potentially competitive services, with the possible
result of a reduced market share, it would be natural for each utility to seek
growth in other markets so as to maintain its size and strength. It makes
further sense to assume that a likely new market for each utility would be the
adjacent section of the state which the utility does not presently serve.
Although there are differences between Northern and Southern Nevada, each
utility certainly knows a great deal about the other utility's territory. The
Commission finds, therefore, that there is a significant likelihood that absent
a merger, each utility would have sought to sell competitive services in the
other utility's service territory.

Under these circumstances, it is inconsistent with the public interest to
approve a merger without conditions that protect the public against this
potential loss of competition. This statement would be true even without the
enactment of the retail competition mandated by the Legislature, since
generation competition at wholesale can benefit the public. The enactment of
Chapter 482 by the 1997 Legislature adds strong support to this finding. The
Legislature has determined that vigorous retail competition in generation
services and other potentially competitive services is in the public interest.
In light of this legislative determination, the Commission can find that the
merger is in the public interest only if there are conditions which prevent the
merger from undermining the public's interest in competition.

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Given the Legislature's declaration that there should be competition in
generation services, and given the Commission's finding that absent the merger
the incumbents likely would compete as builders and sellers of generation in
each other's territories, the Commission conditions this merger on the Joint
Applicants carrying out their commitment, set forth in their merger application,
to divest themselves of their generation units. Such divestiture shall follow
the principles set forth later in this order.

2. Potentially Competitive Services Other Than Generation

Although the Commission here will condition its approval of the merger on the
divestiture of generation, it will not require as a separate condition the
divestiture of other potentially competitive services. The Commission does not
intend this decision to indicate a view that the loss of a major potential
competitor in the markets for these other services is consistent with the public
interest. In fact, the Commission, as indicated above, is concerned about this
effect. However, each of the Joint Applicants has pending before the Commission,
under NRS 704.980(1), a separate application to provide potentially competitive
services, through a joint venture with the other Joint Applicant. The
Commission's decisions in those dockets will in effect determine whether
affiliates of the merged company will be permitted to provide potentially
competitive services. Alternatively, if for some reason those applications were
withdrawn or rejected, the merged company through an affiliate would have to
submit its own application to provide potentially competitive services. In these
dockets, either the pending ones or a future one initiated by the merged
company, the Commission would decide whether the merged company may provide
potentially competitive services other than generation.

Consequently, the Commission in approving this merger subject to a condition
requiring the divestiture of generation but not the divestiture of potentially
competitive services other than generation, is not stating that a merger of two
established companies, each of which might be a competitor of each other in
these markets, is in the public interest; but rather is stating that the public
interest is protected by virtue of the Commission's ability and intent to
determine in other dockets the effect on the public of any loss of competition
in those markets, and the fact that such determination will occur before the
merger actually affects those markets.

3. Requirement of Additional Conditions

As noted above, the Commission finds that the merger will not be in the public
interest absent generation divestiture. The Commission further finds that the
generation divestiture cannot be in the public interest unless the divestiture
process conforms to the principles later set forth in this opinion. Further, the
Commission finds that the generation divestiture, which is necessary to a
finding that the merger proposal should be approved, will not itself be in the
public interest unless there is an independent system administrator and a
generation aggregation tariff in place which the Commission has found are
themselves consistent with competition in Nevada.

The Commission notes that the Joint Applicants offer to use proceeds from the
divestiture of generation assets to increase transmission capacity, and argue
that such increase will enhance competition, however, the Commission must
discount this argument because it is rejecting below this portion of the plan.
As explained below, the Commission cannot know at this time whether the
deployment of divestiture proceeds to transmission and distribution assets will
lead to overinvestment in these assets; under our statutes, an integrated
resource plan proceeding is necessary to make that determination. Moreover, the
proper treatment of the divestiture proceeds is, as discussed below, to offset
book costs in the determination of recoverable costs under NRS 704.983.

The discussion in Part II elaborates on these points.

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II. Implementation of Structural Conditions on the Merger

A. Overview

1. Positions of the Parties

Nevada Power Company, Sierra Pacific Resources, and Sierra Pacific Power
Company, jointly referred to as the "Joint Applicants," have asked the
Commission to approve the implementation of the Merger Agreement dated April 29,
1998 and find that the proposed merger in conjunction with: (1) the plan for
divestiture of generation assets, (2) the use of the proceeds from the sale of
generation assets to support transmission and distribution improvements, and (3)
the amortization of the after-tax gain on the sale of generation assets over
three years to offset generation-related stranded costs and restructuring
transition costs, with the balance, if any, to be shared with customers through
an incentive rate mechanism, is in the public interest.

Mr. Niggli, President and Chief Operating Officer of Nevada Power Company,
testified that Nevada Power had to find a way to reduce the dividend without a
significant loss in stock price to satisfy shareholders. The company was able to
accomplish this objective by reducing the dividend in conjunction with the
proposed strategic repositioning of the company through divestiture. (Tr. at
93.) The merger is critical to the divestiture of the companies' generation
assets to assure that shareholders do not lose value. Without the merger, the
Joint Applicants argue that divestiture would be nearly impossible. (Tr. at 255)
As a result of the merger, Mr. Niggli also believes the Joint Applicants will be
in a stronger position to compete with other market entrants than they otherwise
would be. (Tr. at 137)

Mr. Douglas Burton, testifying on behalf of the Mirage/MGM testified that
without any generation or transmission synergies between the companies, the
decision to divest should be independent of the decision to merge and that
coupling the merger decision with generation divestiture is not in the public
interest. (Ex. 20, p. 14)

Mr. Mark Garrett, testifying on behalf of the Mirage/MGM, argued that the Joint
Applicants' proposed order of regulatory events to unbundle costs and implement
retail open access is an inversion of the preferred order accepted throughout
the industry. Mr. Garrett states that the Joint Applicants propose to first gain
approval to divest their generation assets, then unbundle by functionalizing and
allocating cost of service in the unbundling docket, and lastly to file a rate
case to establish a revenue requirement. Mr. Garrett contends that the preferred
order of regulatory events throughout the industry to unbundle costs and move to
open access with divestiture as part of an overall plan would be quite
different. The preferred order would be to first file a rate case to establish
actual revenue requirements, then unbundle by functionalizing and allocating
costs of service in the same docket, and then divest the generation assets. Once
this is completed, the Joint Applicants could then file for stranded cost
recovery. (Ex. 21, p. 8)

Dr. Blank, testifying on behalf of the Regulatory Operations Staff, stated that
although generation divestiture is a positive feature of the overall
application, the absence of many critical specifics about the Joint Applicants'
proposal significantly reduces the public interest value of the divestiture.
(Ex. 31, p. 3)

2. Commission Decision

The proposed schedule and divestiture process as envisioned in the Joint
Applicants' proposal cannot assure this Commission that the merger will not
impede the orderly development of effective competition. This issue is fully

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discussed in the following sections of the Commission's decision. Therefore, the
Commission will grant conditional approval of the merger only if the Joint
Applicants divest their generation assets in a process and manner that is filed
with the Commission in accordance with the conditions outlined in this opinion
and order.

The Commission believes that the Joint Applicants have proposed a reverse order
of events that need to take place to effectuate the merger in the public
interest, thereby placing the cart before the horse. The Commission adopts the
general process recommended by Mr. Garrett as supplemented by Mr. Schoenbeck and
accepts their reasoning that it is the only logical manner through which both
ratepayers and shareholders can truly benefit from the merger and divesture.

The Commission therefore directs the following procedures be followed as a
condition of approving the merger: (1) file individual rate cases by company to
establish actual revenue requirements pursuant to NRS 704.986 and the
regulations adopted by this Commission, (2) unbundle costs by functionalizing
and allocating costs of service as ordered in Docket Nos. 97-8001, 97-11018 and
97-11028, (3) divest generation assets as specified in a plan of divestiture
which comports with the standards set forth herein and is filed with the
Commission, and (4) submit, pursuant to NRS 704.983 and Commission regulation,
an application to recover recoverable stranded costs for those services
determined to be potentially competitive. The following sections of the
Commission's decision define with more specificity the requirements to be met
prior to consummation of the merger.

B. Divestiture Implementation Process

1. Divestiture Plan

a. Positions of the Parties

The Joint Applicants propose that the divestiture plan be implemented upon full
and unconditional authorization of the merger, on tentative schedules described
in testimony, and in a two-phase sealed bid auction with no less than three
bundles each in northern and southern Nevada. (Ex 4, p. 19) The divestiture
process described in the Joint Applicants' testimony is limited in that it
simply states that Credit Suisse First Boston will assist in the design and
implementation of an auction process.

Mr. Greedy, testifying on behalf of Staff, contends that it is apparent from the
application that approval of the merger application as submitted would include
approval of a "divestiture plan." However, he believes that the Commission
cannot approve the filing as submitted and therefore approve a "divestiture
plan" because the filing does not contain the detailed and comprehensive
information necessary for approval of such a plan. (Ex 33, p. 5) Mr. Greedy
argues that in the application, the Joint Applicants commit only to informing
the Commission as the plan unfolds as illustrated in the direct prefiled
testimony of Steven Oldham which states, "Without compromising the integrity of
the sealed bid auction, the companies will keep the Commission informed
throughout the process of the details of our progress toward divestiture. If in
the future we have information that another date for final divestiture would be
more appropriate, we will so advise the Commission." (Ex 11, p. 13)

Ms. Thomas, Director of Regulatory Operations for the Staff, testified that
without filing a specific divestiture plan with the Commission, the Joint
Applicants would have the flexibility to include improper conditions on the sale
of the plants. For example, as part of the sale, the Joint Applicants could
require a buyer to sell capacity and energy back to them for a specified period
of time at a specified rate in order to meet rate freeze offerings made by the
Joint Applicants in their FERC filing for wholesale customers. (Tr. at

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1589-1590.) In addition, Mr. Russell, testifying on behalf of Staff, argued that
the proposal of the Joint Applicants (as potential alternative sellers) would,
in effect, place the Joint Applicants in the enviable position of having total
control over who they will purchase power from in the future by dictating how
the generation units are bundled for sale, determining which bidders will be
allowed to purchase the assets, and possessing the ability to engage in
potentially anticompetitive conduct through side deals in the future treatment
of competitive affiliates. (Ex. 26, p. 5)

Joint Applicants' own witness Mr. Osborne indicated most divestitures handled by
CSFB and of which he was aware included prior regulatory approval of the
process. He said preapproval of the divestiture process by regulatory bodies
lends certainty to the process, thereby increasing the value of the assets to be
divested.

Staff also recognized that preapproval by the Commission of the divestiture
process would provide certain surety to the Joint Applicants that the sale price
from the assets would be the fair market value of the assets, which will be a
consideration in the upcoming stranded cost proceedings. However, the Joint
Applicants would still be at risk to assure that the process is implemented as
outlined in the approved divestiture plan. (Tr. at 1562-63.) Preapproval of the
divestiture plan would also avoid a situation where the Commission would have to
place conditions on the final sale and transfer of the assets after the auction
has been completed. Therefore, it is advantageous to all parties that the
conditions of the sale of the assets be established prior to the auction. In so
doing, proper notification of the terms and condition of the sale would be known
by potential buyers. (Tr. at 1602.)

b. Commission Decision

The Commission finds that the merger filing submitted by the Joint Applicants
does not include a comprehensive divestiture plan, nor does it contain the
information necessary for the Commission to approve the divestiture as proposed.
Consequently, it is not possible for the Commission to find that the merger
proposal, in its present form, is in the public interest. The Commission cannot
find that a transaction is in the public interest when the method of carrying
out a key element (divestiture) remains unknown. The Joint Applicants have
provided only possible suggestions for a divestiture plan as illustrated in
Exhibits 34 through 38 and were unable to provide any specific final details
about the plan. For example, when asked about the divestiture plan, Mr. Niggli
responded that the divestiture plan is a living document that is defined by a
framework. (Tr. at 93.) In particular, the Joint Applicants' filing is missing a
complete offering memorandum which is critical to how a potential bidder is
going to offer his bid, it lacks how labor force separation will be addressed,
it has no established plan for operational coordination among the divested
plants, it lacks a specific generation aggregation tariff under which the plants
would be required to sell into the retail markets and lacks a specific proposal
for an independent system administrator. In particular, these latter elements,
the generation aggregation tariff and the independent system administrator, are
critical to ensuring that the divestiture itself is consistent with the public
interest, since absent such elements it is not possible to ensure that the
divestiture will result in a generation market that is free of the harms which
can flow from horizontal and vertical market power.

The Commission believes that a divestiture plan which includes the elements set
forth below would provide benefits to both the Joint Applicants and potential
purchasers of the generation units.

Therefore, the Commission finds that the application does not contain sufficient
information that the proposed divestiture plan as envisioned by the Joint
Applicants is in the public interest. However, the Commission believes this can

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be remedied through submittal of a final proposed plan to the Commission prior
to the auction process as a compliance item to this order. Much information was
provided by Staff witness Greedy as to what some of the components of the plan
should be. The plan shall include, at a minimum, the proposed generation auction
design and key conditions in the offering memorandum, including any generation
bundles which are specified and a showing that the bundles will result in the
maximization of competition in the generation markets in northern and southern
Nevada without a significant diminution in the value of the assets, and all
terms and conditions under which the new owners will be obligated to provide
service. Such terms and conditions shall include, but are not to be limited to,
commitment by the bidders to sell the output under a FERC-approved generation
aggregation tariff (GAT) (with the specifics of such tariff to be set forth in
detail as an appendix to the plan to be submitted to the Commission), commitment
to reasonable terms for any must-run contracts necessary for reliability,
commitment to contractual relationships with an Independent System Administrator
(ISA) and/or the control area operator (with the specifics of such contractual
relationships to be set forth in detail as an appendix to the plan to be
submitted to the Commission before submittal to the FERC), and commitment to
abide by all Commission regulations for participation in retail markets.
Elaboration on the ISA and GAT issues appears in various subsections below.

The plan also should make clear to prospective bidders the statutory requirement
that those seeking to sell generation services at retail in Nevada must obtain a
license from the Commission, and that acquisition of generation pursuant to a
Commission-approved divestiture process does not itself constitute the granting
of a license. It is through this licensing process that the Commission will
fully ensure that the divestiture of generation units is consistent with the
development of retail competition as mandated by the Legislature.

The Commission will establish an expedited procedural schedule for Commission
consideration of the Joint Applicants' divestiture plan. By doing so, the
Commission will be providing bidders relative certainty as to the bid process.
The resulting decrease in uncertainty should enhance the sales value of the
plant.

2. Generation Bundles

a. Positions of the Parties

The Joint Applicants contend that the proposed generation bundles to be used to
auction off each company's generation assets represent the optimal packaging of
the units in order to maximize generation competition in both the northern and
southern Nevada generation markets while at the same time maximizing the value
of the bundles to potential buyers. In selecting the bundles, the Joint
Applicants argue that economies of scale and scope of the generation units in
Nevada make it more economical for consumers to make the bundles sufficiently
large and incorporate a transitionary plan to address market power until
workable competition exists in the markets. (Tr. at 2747.)

Mr. Russell, testifying on behalf of Staff, argued that the maximization of
price should not be the driving criterion in the sale of the assets because this
will likely result in concentrated ownership of generation in a divested
marketplace. (Ex. 26, p. 5) Moreover, the Frankena market power study submitted
to the Commission in September 1997 in Docket No. 95-9022 recognizes that
bundles of generation for sale in a divestiture of Nevada utility generation
assets would be considerably smaller than the average bundle sold in other
states due to the size and nature of the markets (small load pockets). Mr.
Russell contends that although smaller bundles may sacrifice some value on the
sale of the assets, they will serve to increase competition and mitigate
horizontal market power. Furthermore, although smaller bundles may prevent
certain large companies from competing in the auction, it will likely attract

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more interest from smaller companies. Smaller bundles will lead to more
competition, which should lead to lower market prices. (Tr. at 1170-71.) In
addition, Staff believes that it is possible that the Joint Applicants may
receive high bids without concentrated ownership because of opportunities for
new buyers to increase the value of the sites and assets by adding additional
units or repowering. (Tr. at 1139-40.)

Other witnesses also raised concerns about the proposed generation bundles. For
example, Staff witness Dr. Blank testified about concerns of the likelihood of
continued market power inherent in the utilities' proposed bundles. As revealed
by the analysis performed by the Brattle Group on behalf of the utilities,
separate ownership of proposed bundles does not eliminate significant market
power possibility. (Ex. 31, p. 6.)

Staff believes that an insufficiently conditioned divestiture of generation
could lead to a worse situation than that posed by vertical integration. (Ex.
26, p. 5.) Mr. Russell testified that in his opinion, there are problems with
the bundles proposed for auction. For example, Bundle E in Sierra's territory
has much lower variable costs than the other bundles. In order to analyze the
effects of the divested bundles on Nevada's generation markets, Mr. Russell
contends that a market power analysis should be done on a time-of-use basis and
differentiate between generation types (i.e., base load, intermediate, peaking).
(Tr. at 1029-30.) Thus, he recommends that the bundles be looked at as part of a
divestiture plan in a separate proceeding.

b. Commission Decision

The Commission recognizes that given the serious constraints in transmission
capacity linking Nevada with other regions, that create problematic "load
pockets" in both the northern and southern parts of the state, it is essential
that the details of divestiture be carefully specified and analyzed in order to
prevent undue accumulation of market power. The Joint Applicants have not proven
that the proposed generation bundles represent the optimal segregation of the
units. The limited information filed by the Joint Applicants consists of a
market power analysis conducted by the Brattle Group. The analysis attempts to
provide a foundation for the companies' assertion that the proposed generation
bundles represent the best balance for maximizing the value of the generation
assets and minimizing generation market power in both southern and northern
Nevada.

The Commission has several concerns regarding the Brattle Group analysis. The
Commission is concerned that the Brattle Group market power analysis did not
include a sensitivity analysis of different combinations of generation bundles
in northern or southern Nevada markets. (Tr. at 2745-46.) The Brattle Group
analysis also includes a very limited sensitivity analysis for new entry in
northern Nevada and no sensitivity analysis for entry into southern Nevada. (Tr.
at 2747.) Other concerns include that the analysis does not include Idaho
Power's share of the Valmy plant in the base case scenario.

The Commission finds that the information contained in the filing does not allow
the Commission to fully evaluate the trade off between expected proceeds and
increased generation competition. Therefore, the Joint Applicants shall include
in the divestiture plan to be submitted to the Commission as a compliance
filing, a comprehensive analysis of the proposed generation bundles which
includes analyses of the impact on the diminution of market power presented by
different generation bundles weighed against the probable impact of those
bundles on the value to be derived from the auction. The Commission also will
give other parties an opportunity to propose alternative bundles.

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3. Indenture Release

a. Positions of the Parties

In order for the Joint Applicants to divest their generation plant, they must
first gain their mortgage indenture Trustee's release of the property. In order
to do so, the Joint Applicants must meet the specific requirements of their
Indentures. Staff recommends that the Commission include a compliance item
requiring the Joint Applicants to file their respective mortgage indenture
Trustee's final opinion allowing for the property release under their respective
mortgage indentures. (Ex. 24, p. 2.)

In rebuttal testimony, the Joint Applicants provided summary legal opinions from
Nevada Power's and Sierra Pacific's Bond Counsels which address the viability of
options available to the companies to release their generation assets. (Ex 81,
RCS-8 & RCS-9). The summary opinion of Nevada Power's bond Counsel, Best, Best
and Krieger, states that they believe that they will be in a position to deliver
an opinion that will allow the generation assets to be released from the lien of
the Indenture. Similarly, Sierra Pacific's bond Counsel, Choate, Hall and
Stewart states that the Trustee is under a contractual obligation to release the
requested properties. The Joint Applicants argue that the legal opinions of the
companies' bond counsels should be sufficient evidence for the Commission to
find that each company's respective indentures will not pose a barrier to
divesting their generation plants. Furthermore, Choate, Hall and Stewart notes
that there is no opinion or other documentation that can be provided by the
Trustee or its counsel with regard to the release. Therefore, the Joint
Applicants argue that the recommendation made by Staff to have a final opinion
of the Trustee prior to merger consummation is not workable.

b. Commission Decision

The Commission finds that the legal opinions of the Joint Applicants' bond
counsels will provide sufficient evidence that the divested property can be
released from each company's respective indentures. Thus, the Joint Applicants
do not need to provide a final opinion of the Trustee prior to final approval of
the merger, but should provide bond counsels' final opinion that the conditions
to release the property specified in the Indenture have been satisfied as part
of the divestiture approval process.

4. Generation Aggregation Tariff

a. Positions of the Parties

For the divestiture process to work efficiently, potential buyers of the Joint
Applicants' generating plants should know the regulatory rules under which they
will supply generation services prior to submitting bids (particularly in
recognition of the existence of load pockets). The Joint Applicants have
proposed to work out the terms and conditions of must-run contracts with
stakeholders, including the Commission. The Joint Applicants state that this
work should be completed prior to the release of the initial offering
memorandum. The Joint Applicants state that the goal of such contracts is to
rely on market forces as much as possible in mitigating market power, rather
than creating a contractual substitute for cost-based regulation. Furthermore,
the Joint Applicants argue against the use of California-style agreements that,
in effect, impose a back-door form of cost regulation on generation. (Ex 11, p.
21.)

b. Commission Decision

The Commission agrees that the Generation Aggregation Tariff (GAT or retail
aggregation tariff) should be filed with the FERC prior to the release of the

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initial offering memorandum. The Commission also agrees with the stated must run
contract objectives outlined in Mr. Oldham's testimony on usage. However, the
proposed GAT tariffs filed by the Joint Applicants in Docket No. 97-8001, and
those referenced in the Brattle Group analysis, are found by the Commission to
be cost-based tariffs designed to collect a revenue requirement through an
additional charge to transmission users. The Commission believes that such
tariffs are very similar to the California must-run agreements and in reality do
not rely on market forces, but on a concept that makes the generators with the
must-run agreements whole.

By allowing the divestiture of the Joint Applicants' generation assets, the
jurisdiction to regulate the output of the generation assets will be transferred
from the Commission to the FERC, to the extent the output is sold at wholesale
rather than at retail. The regulation of these assets will be critical to the
success of the state's retail access program given the severe load pocket
conditions and potential for market power in the state. Therefore, before the
merger can take effect, the Commission finds that any tariff for sales of
generation services to retail aggregators from load pocket generators which is
submitted to the FERC must further the legislative objectives of encouraging and
enhancing the development of a competitive generation market in the State of
Nevada. The tariff shall be consistent with a consensus proposal from Docket No.
97-8001 or, in the absence of a consensus proposal, be consistent with the
Commission's principles outlined in Docket No. 97-8001. More specifically, the
Commission finds that the tariff must rely, as much as practicable, on market
forces while sufficiently protecting consumers from potential harm due to the
existence of load pockets. The proposed terms and conditions under which the
divested generation units will operate in Nevada should be included as part of
the Joint Applicants' divestiture plan to be filed with the Commission as a
compliance item in this docket.

5. Independent System Administrator

a. Positions of the Parties

The Joint Applicants have also committed to work with stakeholders, including
the Commission, to formulate an interim independent system administrative
solution that, should the Joint Applicants pursue retail energy marketing
through an affiliate, will satisfy the Commission's concerns about potential
anticompetitive conduct.

Mr. Russell, testifying on behalf of Staff, argued that divestiture by itself
will not eliminate all vertical or horizontal market power in either service
territory. Therefore, a strong Independent System Administrator (ISA) must be
implemented and the Commission should look closely at the size and form of the
generation bundles to be divested in concert with an acceptable Generation
Aggregation Tariff. (Tr. at 1250.) Again, as Staff points out, it is important
that potential buyers know the regulatory rules under which they will supply
generation services prior to submitting bids. (Ex. 31, p. 3.) If an ISA
structure is proposed to FERC, prospective buyers of the Joint Applicants'
generation assets need to know what interaction they are expected to have within
that framework. Staff recommends that the Commission establish an expedited
proceeding for approval of a detailed ISA plan that could be filed for FERC
approval. (Ex. 31, p. 7)

Mr. Goldsmith, testifying on behalf of Coastal Power, stated that Coastal's
overriding concern relates to transmission access. He argued that a strong ISA
with control over generation dispatch which is on a path towards an ISO is
crucial to attracting new generation to Nevada. (Tr. at 787)

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b. Commission Decision

The Commission agrees with Mr. Russell that the Joint Applicants must have a
well-defined ISA prior to the divestiture of generation. In addition, the
Commission has the obligation and duty to ensure that an independent system
administrator is implemented in a manner that fosters competition at the retail
level in Nevada. Therefore, as part of the divestiture plan to be filed as a
compliance item in this docket, the Joint Applicants shall include the proposed
details of an ISA, including the organizational and governance structure and
extent of its operational control sufficient to demonstrate to the Commission
that the ISA has the independence necessary to preclude, to the extent possible,
anticompetitive conduct by the transmission owners. Before the merger can take
effect, an ISA proposal that is consistent with the implementation of retail
competition in Nevada must be submitted to the FERC. In order for the ISA to be
consistent with the implementation of retail competition in Nevada, the
Commission finds that the ISA submitted to the FERC must be consistent with a
consensus proposal from the parties in Docket No. 97-8001 or, in the absence of
a consensus proposal, should be consistent with the principles outlined by the
Commission in Docket No. 97-8001.

C. Allocation of Divestiture Proceeds

1. Proceeds up to Book Value

a. Positions of the Parties

The Joint Applicants propose to reinvest the proceeds from the sale of their
generation assets into the construction of new transmission and distribution
facilities. Mr. Niggli testified that the proceeds from the divestiture up to
book value should be reinvested at the Joint Applicants' discretion. (Tr. at
123.) The application states that the proposal is based on investor expectations
that the proceeds from the sale of a rate based asset either be returned to the
investor or reinvested in operating property with comparable earnings potential.
The Joint Applicants argue that reinvestment of the proceeds from the sale of
generation into the construction of new transmission and distribution facilities
is suitable from the perspective of the investor and will enhance the market
opportunities available to retail energy customers. (Ex. 4, p.19.)

The Joint Applicants expect approximately $1 billion in proceeds from the
divestiture. However, the current construction budget for transmission and
distribution facilities is only $300-$350 million. (Tr. at 181.) Mr. Oldham
recognizes in his testimony that the timing of suitable reinvestment
opportunities may require some balance of investment and share repurchases.
Thus, the Joint Applicants propose that reinvestment be carefully coordinated to
minimize the loss of earning power that will inevitably follow the sale of
utilities' assets. (Ex. 57, pp. 15-16.) However, the Joint Applicants, through
Mr. Davis' testimony, are not seeking in this filing approval for any specific
projects but merely have attached an illustrative list of possible projects, the
cost-benefit of which have not been evaluated.

Several intervenors raised concerns about the Joint Applicants' proposal to
reinvest the proceeds from the sale of the generation assets into new
transmission and distribution projects. Mr. Winterfeld, testifying on behalf of
Mt. Wheeler Power and Deseret G&T, testified that reinvesting monies from
generation divestiture in costly and potentially cost-ineffective transmission
projects has the real potential to increase the delivered cost of power to all
Nevada ratepayers (those of the Joint Applicants), as well as the ratepayers of
Mt. Wheeler and other utility systems purchasing transmission service from the
Joint Applicants. (Ex. 67, p.4) Uneconomic investment in transmission facilities
will unnecessarily raise transmission costs into and out of the region.
High-cost transmission would deter generation providers from selling outside the
state. (Tr. at 788.)

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Dr. Rosen, testifying on behalf of the UCA, argued that the correct economic
test for whether a transmission and distribution company should make new
investments is still the traditional Integrated Resource Planning based test,
except that once markets are open to competition, the test should utilize the
market price for generation when analyzing the trade-off between investing in
new transmission versus new generation. (Ex. 32, p. 8) Dr. Fox-Penner, who
provided rebuttal testimony for the Joint Applicants, seemed to agree in stating
that transmission planning should continue to be done through the integrated
resource planning framework, taking into account competitive generation markets.
(Tr. at 2758-59.)

b. Commission Decision

The Commission finds that any investment in transmission facilities must first
be approved by the Commission in an integrated resource plan filing. Allowing
all proceeds up to book value to be reinvested in transmission facilities will
likely result in excess capacity for the region and higher rates for all
customers. The conditional approval of the merger in no way should be
interpreted as preapproval of any of the potential transmission projects listed
in Exhibit 12, Attachment MHD-2, of the Joint Applicants' merger filing.

The Commission finds that the use of proceeds up to book value (excluding any
goodwill allocation) should be left to the discretion of the companies (subject
to the Commission's approval of expenditures which are subject to the integrated
resource plan process); however, the Commission cannot allow the addition of
facilities that are not proven to be used and useful into either company's rate
base. Therefore, the Joint Applicants may be in a position of repurchasing
shares until such time as new investment in transmission and distribution
facilities is warranted and approved by the Commission in an integrated resource
plan filing and rate case proceedings.

2. After-Tax Gain on Sale of Generation Assets

a. Positions of the Parties

The Joint Applicants propose that any after-tax gain on the sale of generation
assets be amortized over three years and first used to offset recoverable costs
related to the designation of generation as a potentially competitive service
(fuel, fuel transportation, or employee-related costs not otherwise recovered
through the auction, as well as energy-related information systems, metering and
billing costs) and transition costs incurred during the move to open access. If
after satisfying the above obligations in any one year of the three-year
amortization period, a net gain is experienced, that gain will be calculated
separately for Sierra Pacific and Nevada Power and flow through the earnings
sharing calculation as a credit to cost of service. (Ex 4, pp. 19-20.)

Staff argues that although the proposal to use gains to recover recoverable
costs initially appears reasonable, further investigation reveals the Joint
Applicants' other proposal to gross up generation book costs by goodwill, and
the exclusion of other significant obligations associated with the designation
of generation as a potentially competitive service in the definition of
potential "stranded costs" greatly reduce the reasonableness of the proposed use
of any gain from the sale of generation. The most noticeable exclusion from the
Joint Applicants' list of potential stranded costs are purchased power
contractual obligations which are proposed to remain in rate base in the
distribution utility. (Ex 31, p.9.)

Dr. Peseau, testifying on behalf of the SNWA, provided similar testimony stating
that other generating or regulatory assets, such as the above-market qualifying
facility contracts, are not considered. Unless all above (and below) market
costs of these QF contracts are considered in the netting of generation sale

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proceeds, the divestiture really becomes a mechanism to require ratepayers to
pay for more than 100 percent of each utility's stranded costs. (Ex 61, p. 15)
In essence, the Joint Applicants' proposal of not netting QF contract costs that
are above market with below-market generation will create higher costs for
end-users.

b. Commission Decision

The Joint Applicants' approach would have the effect of predetermining which
costs are to be considered "stranded." This result would be inconsistent with
NRS 704.983. The Commission interprets that legislative directive as requiring
that the Commission use the after-tax gain on the sale of generation assets to
offset book costs in determining recoverable stranded costs. This "netting"
process ensures that ratepayers receive their fair share of the proceeds from
divestiture. The Joint Applicants' approach would circumvent this requirement.

Moreover, the activity of purchasing power from qualifying facilities (QFs) and
reselling to retail customers falls squarely under the definition of aggregation
service and is therefore a potentially competitive service. It is undisputed
that the power purchased from the QFs by the Joint Applicants is at a price
above the actual market price of energy in almost all hours of the year. The
Joint Applicants will therefore want an opportunity to have these costs
classified as recoverable costs under NRS 704.983 and to propose a means for
their recovery. The Commission has issued proposed recoverable costs
regulations. Those regulations, and future proceedings thereunder, should help
to illuminate the information and analyses needed to determine recoverable
stranded costs.

The Commission therefore will treat recoverable costs in the manner prescribed
by NRS 704.983.

The Commission understands the Joint Applicants' desire that shareholders share
in the benefits of a successful divestiture process beyond simply recovering
those costs determined to be recoverable stranded costs. Mr. Oldham repeatedly
spoke of "incentives" to encourage the development of good practices in utility
operations. However, the Commission believes management and shareholders also
should face incentives to minimize stranded costs. Therefore, if the after-tax
gain on the sale of the generation assets is greater than the Joint Applicants'
recoverable stranded costs, taking into consideration statutory considerations
enumerated in NRS 704.983, the remaining portion shall be available to buy down
the goodwill acquisition premium in the manner set forth in Section II of this
opinion. The Commission therefore encourages the utilities to aggressively seek
to reduce their recoverable costs so as to increase the remainder of the gain
available to buy down the goodwill acquisition premium. In the event that the
Commission determines that there are no material recoverable costs due to the
Joint Applicants pursuant to NRS 704.983, the Commission shall open a proceeding
in order to determine the appropriate sharing of the gain on the sale of the
assets between ratepayers and shareholders.

The accounting treatment of the goodwill acquisition premium is discussed in
detail in Section III. The treatment of the goodwill premium as outlined in this
order is the sole means by which the Joint Applicants may seek recovery of the
premium. For example, the Commission will not entertain requests in the
recoverable cost proceeding under NRS 704.983 for treatment of goodwill costs as
recoverable costs. Upon completion of divestiture and of the recoverable cost
proceeding, the Commission will issue a separate order specifying how the Joint
Applicants are to reconcile the resulting gain and costs.

Finally, all proceeds from the sale of the Joint Applicants' generation assets
shall be allocated to each respective company's books. There shall be no
cross-subsidization between Nevada Power and Sierra Pacific customers by
commingling any divestiture proceeds between the two companies.

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III. Effect on Costs and Rates

A. Cost Reductions Achieved by the Merger (Merger Synergies)

Since the Commission has determined that the merger would not be in the public
interest absent divestiture of the companies' generation assets, the following
discussion focuses entirely on merger savings estimates excluding generation.

1. Positions of the Parties

The Joint Applicants initially estimated that synergy savings from the merger
would approximate some $350 million pre-tax over ten years, net of $50 million
in costs to achieve. (Ex 11, SCO-3.) Estimated savings include labor and
corporate administrative programs net of costs to achieve, and pre-merger
initiatives. The combined companies also expect to be positioned to meet system
growth with an improved financial profile. The combined companies assert they
will have a lower cost of capital which will benefit ratepayers at the time of
the next rate case. (Tr. at 1808.) The Joint Applicants state that although it
is much easier to identify and measure costs than to measure the benefits of the
merger, there are ways to estimate merger benefits and those estimates are five
times the magnitude of the costs. (Tr. at 1813.)

Mr. Brosch, testifying on behalf of the UCA, testified that the merger savings
stated in Mr. Oldham's testimony and Attachment SCO-3 are significantly
overstated. After making corrections for double counting certain employee
benefits savings and removing savings that would be achievable without the
merger, Mr. Brosch finds that the correct estimate should be reduced to $323
million. The Joint Applicants did not dispute Mr. Brosch's corrections and
subsequently changed their initial estimates to those of Mr. Brosch. (Ex. 47, p.
8) Mr. Brosch noted that the Joint Applicants' savings estimates are built
entirely upon assumptions about staffing plans, wage rates, inflation rates,
software development plans, capital costs, purchasing synergies and overhead
costs. Most of the predicted savings are generated by assumptions regarding
staffing reductions, inflation rates, purchasing leverage, and the combination
of computer data centers. However, as pointed out by Douglas Burton, testifying
for the Mirage/MGM, the proposed merger does not identify any strategic or
technological synergies associated with generation, transmission, or
distribution.

Mr. Brosch argues that the merger savings estimates sponsored by Mr. Oldham, as
revised, are not reasonable and that they involve speculation regarding a
multitude of assumptions that cannot be supported or audited. In fact, Mr.
Brosch argues that the assumptions employed tend to overstate savings by
escalating assumed savings over ten future years for comparison to current
costs. Therefore, he recommends that a relatively high ratio of estimated
savings to merger costs should be demanded by the Commission, to mitigate the
risk that actual, realized merger savings in the future may not fully
materialize to offset the significant merger costs. (Ex. 47, p. 15.)

Mr. Garrett, testifying on behalf of the Mirage/MGM, also raised concerns about
the Joint Applicants' estimates for merger savings. Mr. Garrett notes that most
of the cost savings are expected to be achieved through the elimination of
approximately 250 duplicative positions. However, Mr. Garrett argues that the
Joint Applicants cannot identify what positions might be eliminated until after
the merger when a "best practices" analysis can be performed. Furthermore, Mr.
Garrett testifies that in responses to data requests issued to examine the
accuracy of the estimated cost savings, the Joint Applicants seemed to retreat
from their savings estimates and rely instead on the hold harmless and rate
freeze proposals to justify the merger. (Ex. 21, p. 11-12)

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Finally, Mr. Brosch argues that the Joint Applicants did not conduct a net
present value analysis of costs and savings. Instead, the Joint Applicants have
calculated annual savings numbers (nominal savings analysis). Mr. Brosch argues
that goodwill and other costs are incurred up front and therefore a net present
analysis would be appropriate. If the Joint Applicants' estimated merger savings
are accepted without revision for apparent overstatements, but are simply
discounted to be on a present or current dollar basis, Mr. Brosch calculates
that merger savings estimates would be reduced to approximately $242 million
using a 10 percent discount rate. The merger costs estimated by the Joint
Applicants total $179 million in the first ten years, but these costs are
largely up front in nature. No discounting is required for merger costs because
these costs are incurred at the front end of the 10-year period and have not
been escalated in the Joint Applicants' presentation. Therefore, Mr. Brosch
finds that the benefit/cost ratio for the merger declines considerably when
comparable dollar savings and costs are compared, and range from about 1.9 to
one to as low as 1.2 to one using a 12 percent discount rate. The UCA argues
that there is a less than comfortable multiple of merger savings to costs and
that it is very possible that merger costs will exceed realized actual merger
savings. (Tr. at 2132.)

2. Commission Decision

The Commission finds that the merger savings are estimates. Furthermore, when
analyzed on a net present value basis, the Commission agrees with the UCA in
that the benefit to cost ratios become uncomfortably low. However, the
Commission is not in a position to specifically calculate savings for the Joint
Applicants since they are just now in the process of assessing the details of
proposed merger savings. Therefore, the Commission finds that the risk of
actually realizing merger savings should be placed squarely on the Joint
Applicants as outlined below in the Commission's decision on ratemaking and
accounting treatment of merger costs and savings.

B. Ratemaking Treatment of Merger Costs and Savings

1. Positions of the Parties

The costs incurred to achieve the merger include the costs related to the merger
transaction ("transaction costs") as well as costs estimated to be incurred for
integration of the two utilities ("transition costs"). A third category of
costs, representing the largest category of costs included in the Joint
Applicants' filing, relates to the markup above book value that Joint Applicants
propose to record as "goodwill" under the purchase accounting required for the
merger.

Concerning this goodwill amount, the Joint Applicants explain that Nevada Power
will be deemed the acquirer, as its former shareowners will own more of Sierra
Pacific than the existing Sierra Pacific shareholders. As a result, an amount
roughly equal to the difference between Sierra Pacific's book equity at the time
of the merger and the exchange price at the time the Merger Agreement was signed
will be accounted for on Nevada Power's books as an asset called goodwill. The
amount of goodwill, which will be determined at closing, is approximately $445
million. (Ex. 53, p. 5) Goodwill will be accounted for on Nevada Power's books
as an asset. The Joint Applicants propose to amortize the goodwill evenly over
40 years which adds an additional $11 million of amortization expense per year
to merger costs.

The Joint Applicants submit that the merger expenses must be recovered entirely
out of merger savings. Mr. Ruelle, Senior Vice President , Chief Financial
Officer, and Treasurer for Sierra Pacific Resources, stated in his direct
testimony that it would not make sense for the Joint Applicants to incur
expenses associated with a merger if they do not recoup the merger expenses and

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further derive some benefit from the merger. (Ex. 53, p. 8.) The Joint
Applicants provided testimony in several instances that they firmly believe that
the savings from the merger are far greater than the total merger expenses,
including the amortization of goodwill (i.e., Ex 53, p. 8; Tr. at 3057.)
Mr. Brosch, testifying on behalf of the UCA, raised the issue that goodwill has
nondeductible tax status. Therefore, including an income tax factor-up, the
10-year revenue requirement associated with goodwill grows to about $170 million
and over 40 years goodwill amortization requires revenues of about $670 million.
(Ex 47, p. 28.) Mr. Garrett, testifying for the Mirage/MGM, also recognized that
goodwill must be grossed up for taxes (Ex. 47, p. 28).

The Joint Applicants propose a long-term freeze in rates for jurisdictional
services, an incentive mechanism through which net merger and restructuring
related benefits are shared equally between investors and customers, along with
a "hold harmless" commitment on merger related costs. The Joint Applicants'
proposal consists of freezing rates for all elements of bundled electric service
for both companies through January 1, 2000. Then, as a result of the
Commission's February, 1999 unbundling docket (which the Joint Applicants see as
not updating cost of service), revenue requirements on jurisdictional electric
assets will remain frozen for at least two years. Two years following the
implementation of retail open access, the Joint Applicants propose to file to
adjust revenue requirements based on regulated cost of service in order to
reflect the actual operational experience of the merged company divested of
generation and providing unbundled noncompetitive electric service. Effective
with the implementation of retail open access, the Companies propose to
calculate annually and share with customers fifty percent of earnings generated
on investments in jurisdictional assets above twelve percent return on equity.
Finally, the Joint Applicants propose that if for some reason the estimated
future savings related to the merger are less than the costs to achieve
(transaction, transition, and goodwill), the Joint Applicants will be
responsible for the shortfall. (Ex. 11, pp. 26-27)

The Joint Applicants argue that their proposed "hold harmless" strategy provides
the new company with the opportunity to generate cost savings, experience and
measure savings during a test year, and reflect actual net savings in cost-based
rates. (Ex. 11, p. 27) Mr. Oldham testified that he believes that incentive
regulation is the best way of bringing merger savings out of the system to
customers. (Tr. at 2654.) Mr. Oldham also argued that savings will flow through
to customers whether it is in the regulated business or the competitive
business. In the competitive business, savings will flow through in the price
paid for competitive services. Therefore, he believes that merger costs should
also be allocated to the competitive business and that goodwill should be
transferred with investment. (Tr. at 2569.) Finally, Mr. Oldham states on page
31 of his testimony that, "If the future savings are less than the costs to
achieve (transaction, transition and goodwill), the companies will be
responsible for the shortfall." (Ex. 11, p. 31)

The Joint Applicants are requesting that the Commission approve "above the line"
treatment of all merger costs. Mr. Ruelle testified that the treatment of these
costs, including the goodwill amortization expense, does not expose ratepayers
to the risk of paying for the merger costs in the event that merger benefits do
not materialize because the merger benefits far exceed the merger costs.
Furthermore, merger costs are accounted for above the line only if there are
sufficient savings to cover those costs. (Tr. at 1904.) In addition, he states
that the merger expenses are easily identifiable in the event that the Joint
Applicants were to demonstrate a revenue deficiency caused by the merger costs.
(Ex. 53, p. 9) The Joint Applicants state they are only asking the Commission
for a reasonable opportunity to recover the costs of the transaction from the
savings attributable to the transaction. (Tr. at 3056.) Goodwill should be
allocated to investment and should therefore follow plant. Thus, any plant moved
from the regulated noncompetitive business should be accompanied by the

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appropriate amount of goodwill. (Tr. at 2569.) Mr. Niggli testified that the
numerous proposals from intervenors to put the acquisition premium below the
line would be an unfair measure because all merger costs would go to
shareholders while all merger savings would go to customers. (Tr. at 1777-1778.)

Staff describes the allocation of goodwill costs to ratepayers as equivalent to
the sale of assets by a utility to itself at a markup above book cost for the
purpose of increasing revenue requirements. Dr. Blank states that although
goodwill may be common for acquisitions in competitive markets, where
shareholders have no guaranteed opportunity for cost recovery, such costs have
no place in regulated utility rate recovery. (Ex. 31, p. 11.) In addition, Dr.
Blank argues that through the intended allocation of goodwill to generation, the
utilities have effectively proposed to sell themselves their own assets and then
expect to have an opportunity to recover the premium they paid to themselves.
(Ex 31, p. 14.)

Mr. Anderson, a Senior Financial Analyst for Staff, provided Staff's
recommendations on the accounting of the goodwill acquisition premium. Staff
recommends that, as a condition of the merger, the Commission specifically
exclude goodwill associated with the merger from all future ratemaking
proceedings. The recommendation includes a condition that none of the
acquisition adjustment be allocated to generation assets. The basis for Staff's
recommendation is that the merger transaction was structured primarily for the
benefit of the Joint Applicants' shareholders and as such, ratepayers should not
bear the burden of these costs. (Ex. 70, p. 2)

Mr. Anderson also testified that merger cost savings can neither be precisely
quantified nor accurately tracked and that the estimates of merger savings
provided by the Joint Applicants should not be relied upon by the Commission.
(Ex. 70, p. 2) Furthermore, to the extent that the Commission incorporates
merger transaction and transition costs into the companies' cost of service in
future rate proceedings, merger savings should be flowed through to ratepayers.
However, Staff argues that such costs should be allowed in rates only to the
extent that they were prudently incurred and that the Companies can establish
that they are offset by verifiable merger savings. Finally, to the extent the
Joint Applicants are requesting inclusion of merger related expenses in their
cost of service in a future rate proceeding, the Joint Applicants should have
the burden to demonstrate the existence of equal or greater than offsetting
merger savings that pass a "but for the merger" test. The test would require the
Joint Applicants to establish that the offered savings would not have occurred
"but for the merger." (Ex. 70, pp. 28-29)

Mirage/MGM witness Mr. Garrett testified that he does not believe that the
Commission should accept a rate freeze as a form of ratepayer protection when
current financial conditions clearly indicate a substantial rate reduction is
warranted for each of the Joint Applicants. However, if the merger were
approved, and assuming the Joint Applicants' revenue requirements were adjusted
to reflect current financial conditions as part of the unbundling docket in
1999, or in another docket contemporaneous with the merger, Mr. Garrett believes
that the appropriate ratemaking treatment of the merger-related savings is to
let the savings accrue to the benefit of the Joint Applicants and their
stockholders until the next rate case proceeding in which the savings may be
reflected in the prospective rates established at that time. (Ex. 21, pp. 13-14)
Mr. Garrett argues that merger costs should also be subject to the same
ratemaking treatment. In effect, the Joint Applicants would enjoy the savings
that resulted from the merger for a period of time and would be responsible for
the costs incurred to achieve the savings as well. Since the costs are incurred
up front and the savings develop over time, the Commission could allow the Joint
Applicants to set up a deferred charge for the costs and amortize the balance
over some period of years. Along with approval of establishing the deferred
regulatory balance, the Commission could agree to examine the costs of the

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merger at the Joint Applicants' next rate case for possible inclusion in
prospective rates at that time. Mr. Garrett argues that this treatment of the
costs to achieve the merger provides a real hold harmless protection to the
ratepayers and effectively places a portion of the risks associated with the
merger on the Joint Applicants. (Ex. 21, p. 15)

The Joint Applicants propose to amortize the goodwill premium to account 495,
which is an above the line account to be collected through rates. Mr. Garrett
argues that the premium should be below the line until such time as the Joint
Applicants can show specific savings as a result of the merger. Although Mr.
Oldham provides assurances that if for some reason the estimated future savings
are less than the costs to achieve the companies will be responsible for the
shortfall, Mr. Garrett testified that there is no practical way to know this
because there is not a mechanism in place to track merger costs and savings. It
is difficult to track merger costs and even more difficult to track savings.
(Tr. at 739.) Mr. Garrett also notes that the proposed sharing mechanism
established on a 12 percent ROE is significantly higher than today's market.
Thus, the Joint Applicants are attempting to set the ROE outside of the
compliance filing in the merger proceeding. An appropriate sharing point should
be around .5 percent above allowed ROE. (Tr. at 747.) Therefore, Mr. Garrett
recommends that the Commission require each of the Joint Applicants to file a
general rate case before the merger. Each company must file separate rate cases
because there will not be data available for a full test year for the merged
company on which to base rates.

UCA Witness Mr. Brosch recommends that goodwill be amortized below the line and
not included in revenue requirements in future rate cases. He recommends that
goodwill not be charged above the line for many reasons, including: it
represents an improper departure from cost based regulation; it unfairly burdens
ratepayers with market gains already retained by shareholders; it significantly
dilutes any potential savings otherwise to be realized from the merger; and it
can be recovered through other benefits from the merger that are expected to be
retained by shareholders. (Ex. 47, pp. 32-33) Mr. Brosch noted in the merger of
Missouri Gas Energy and Southern Union, certain merger benefits were retained by
the shareholders in lieu of goodwill recovery. This method gives the company an
opportunity to demonstrate savings. (Tr. at 2137.) Mr. Brosch also testified
that the Joint Applicants do not provide any specific means of allocating
goodwill costs between Nevada Power and Sierra Pacific. However, there is a
proposal "on the table" to allocate the costs based on relative assets. Mr.
Brosch recommends that this needs to be addressed within the context of separate
ratemaking for Sierra Pacific and Nevada Power. (Tr. at 2256.)

Mr. Brosch also recommends that rates not be frozen at present levels because
there has been no showing by the Joint Applicants that present rate and revenue
levels are reasonable in relation to current rate base, cost of capital, expense
and revenue levels. Rates should not be frozen when so much remains unknown
about whether current rates are reasonable. (Ex. 47, p. 50) Mr. Schmalz,
testifying on behalf of the Joint Applicants, acknowledged that the cost of new
debt has declined over the past few years. (Tr. at 2021.)

The absence of any income tax deductions for goodwill amortization expense
further detracts from the net savings estimates prepared by the Joint
Applicants, according to Mr. Brosch. He added that ratepayers should not be
exposed to the risks that large and very certain merger costs will be charged,
while commensurate levels of merger-related savings may or may not eventually
materialize. (Ex. 47, p. 36) Mr. Brosch also testified that the Joint
Applicants' projections of merger transition costs are highly uncertain and that
the actual transition costs to be incurred will not be known for some time. The
total estimated transition cost amount in the Joint Applicants' filing is $46.2
million (exclusive of transaction and goodwill amortization). Mr. Brosch
proposes that severance costs incurred for non-executives be eligible for

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deferral for any formal severance plan adopted and effective within 12 months of
closing of the merger transaction. The 12-month cutoff should, according to Mr.
Brosch, enable the Joint Applicants to evaluate the staffing levels of the
integrated companies and the requirements of the new organization and then
design and implement severance arrangements tailored to accomplish staffing
requirements. At the same time, Mr. Brosch argues that the use of such a cutoff
will prevent later workforce adjustment programs that may occur from being
inappropriately attributed to the merger. Any deferred costs associated with
severance and other employee separation costs, Mr. Brosch argues, should be
limited to actual payments to employees or third party vendors for the benefit
of separating employees. Employee relocation costs, he adds, should be treated
in the same manner. Finally, Mr. Brosch advocates that all such deferred costs
should be subject to regulatory review and audit in each utility's next formal
rate proceeding. Amortization of deferred costs should commence in the month of
transaction closing. All executive separation and change in control payments
costs should be borne by shareholders. (Ex. 47, p. 44)

Mr. Parcell, a cost of capital witness testifying on behalf of the UCA, stated
that the facts surrounding Sierra Pacific's 12 percent sharing mechanism have
changed and, furthermore, Sierra Pacific's ROE should not automatically be
utilized for Nevada Power. (Ex. 65, p. )

Dr. Peseau, testifying on behalf of the SNWA, argues that the Joint Applicants'
merger proposal attempts to sidestep the crucial revenue requirement and cost of
service issues necessary to properly prepare for the implementation of
competition by requesting that rates be frozen at existing levels. Without new
cost of service studies, the Joint Applicants stand to enjoy the present
above-market rates of return they have been experiencing by virtue of the many
years of fixed base rates of each of the utilities at the time that cost of
capital has fallen dramatically. (Ex. 61, p. 2) Dr. Peseau recommends that the
Commission order immediate general rate cases for both utilities to align rates
and costs prior to or, preferably, in place of, an incentive earnings mechanism.
In the alternative, the earnings sharing mechanism could be modified to mitigate
the need for future general rate cases. For example, the Commission could
approve an earnings deadband around an authorized rate of return with an index
to have the authorized ROR change with changes in capital markets.(Tr. at 2126)

2. Commission Decision

Given the uncertain benefits associated with this merger, the Commission finds
that it is not appropriate to place on ratepayers the risk that they will have
to pay for merger costs without receiving merger benefits. Utility management
designed the transaction, arranged the terms and incurred the costs. The Joint
Applicants have not persuaded the Commission that the transaction will enhance
the Joint Applicants' ability to fulfill their legal obligation to serve
ratepayers at reasonable cost. Rather, it appears that the Joint Applicants
entered into the transaction to advance their competitive interests. That goal
is not necessarily inconsistent with the public interest, but it is not one for
which ratepayers of the Joint Applicants' noncompetitive services should bear
risks. Under these circumstances, the risk that merger savings will be
insufficient relative to merger costs is a risk that should be borne by the
company's shareholders. The Commission therefore will establish a procedure that
affords the shareholders a reasonable opportunity to recover these costs, upon a
showing that merger savings are sufficient to justify these costs.

a. First Step: Setting Cost-Based Rates for the Merging Companies

The current rates of both companies are based on negotiated settlements that are
several years old. The Joint Applicants provided no new cost of service
information upon which the Commission could evaluate the reasonableness of those
rates under current conditions. Therefore, there is not sufficient information

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in the merger application for the Commission to determine that the rate freeze
proposed by the Joint Applicants would result in reasonable rates at this point
in time.

Consequently, the first step must be to set rates based on the actual cost of
providing service within a recent test period. Otherwise, any mechanism for
assigning costs and benefits will not have a correct cost foundation. In order
to expedite this merger process, as well as avoid unnecessary overlaps with the
implementation of competition required by the Legislature, the Commission will
condition its merger approval on the Joint Applicants making certain submissions
within the compliance process set forth in NRS 704.986. Specifically, each
company shall make compliance filings when directed by the Commission in 1999 in
two different phases. The first phase will consist of determining a new revenue
requirement for each separate company and allocating or directly assigning that
revenue requirement to the list of unbundled services outlined in the applicable
Commission's orders in Docket Nos. 97-8001, 97-11018, and 97-11028. No merger
costs nor merger savings shall be included in these filings. This revenue
requirement will be effective as of the beginning date of competition, December
31, 1999, assuming the merger has been effectuated by that date. If the merger
has not been effectuated by that date, or if competition does not begin on that
date, the Commission will issue, before that date, an appropriate revision to
this section of the opinion. The second phase will consist of setting rates for
noncompetitive services.

This approach ensures that the Joint Applicants' opportunity to recover costs
based on savings resulting from the merger (described below) is based on actual
costs and is consistent with statute, which requires the companies' compliance
filings to encompass the establishment of new rates in anticipation of the
transition to retail competition. This is clear from the plain reading of NRS
704.986 which in part states:

The vertically integrated electric utility shall include with the plan any
information the Commission needs to:

(a) Set rates for electric services, including, but not limited to:

(1) A statement of the costs of the vertically integrated electric utility to
provide the service.

(2) The amount of revenue required by the vertically integrated electric
utility.

(b) Allocate among customers the costs of service and the requirements for
revenues for noncompetitive services.

The Commission's approach thus prevents duplication and delay while expediting
both the merger approval process and the process for preparing for competition.

b. Second Step: Instituting a Mechanism for a Fair Opportunity to Recover
Merger Costs

The Commission finds that the cost treatment of merger costs and credit for
merger savings similar to that proposed by Mr. Garrett in Exhibit 21 shall be
used to recover merger related costs. Specifically, the merger cost recovery
mechanism will have the following principles:

1. Once the new rates established in the 1999 compliance proceedings are
imposed, they will be frozen for a period of three years. During this
period, the Joint Applicants shall enjoy the savings that resulted from the
merger and will at the same time be responsible for the costs incurred to
achieve those savings as well. At the end of the three-year period, the

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Joint Applicants shall file a general rate case (GRC). The Commission finds
that this will allow an adequate period of time for the anticipated savings
from the merger to materialize.

2. Since the costs of the merger are incurred up front, the Joint Applicants
shall establish deferred accounts for three categories of costs:
transaction costs, transition costs, and goodwill costs.

3. For each of these three categories, the Joint Applicants must assign or
allocate the costs between potentially competitive services, noncompetitive
services, and unregulated services and explain such assignment and
allocation in detail. Only merger costs properly assigned or allocated to
noncompetitive services will be eligible for recovery, since it is a tenet
of utility regulation that ratepayers of noncompetitive services should not
pay in regulated rates for costs properly assignable or allocable to
potentially competitive services or unregulated activities.

4. Transition costs, transaction costs and goodwill costs, after being
properly assigned or allocated to noncompetitive services, will be deemed
eligible for recovery from ratepayers upon a showing that the level of such
costs was prudent and that merger savings are sufficient to cover such
costs. The Commission's review of prudence in the GRC will provide an
opportunity for the parties to address these prudence issues, including
such issues as the executive compensation and severance pay for
non-executives raised by Mr. Brosch. Such prudent, properly attributed
costs will be deemed to be "eligible transaction costs," "eligible
transition costs" and "eligible goodwill costs."

5. In their GRC filing, the Joint Applicants will propose an amortization
period for the eligible transition, transaction costs, and goodwill costs.
The Commission will then review the merits of the costs incurred to achieve
the merger in light of the actual savings produced by the merger. If the
Commission determines that the savings due to the merger are sufficient to
cover a portion (or all) of the eligible transaction and transition costs,
the Commission will include that portion of the eligible transition and
transaction costs in rates. The Commission finds that this treatment of the
costs to achieve the merger provides a real hold harmless protection to the
ratepayers and effectively places a portion of the risks associated with
the merger on the Joint Applicants.

6. The Commission will also allow the Joint Applicants to propose the
inclusion of the eligible goodwill costs in rates in their GRC filing. The
Joint Applicants must support this inclusion with a demonstration that the
synergies achieved through the merger have resulted in actual savings in
excess of the eligible transition and transaction costs to the ratepayers
that could not have been achieved without the merger.

The Commission finds that the above methodology provides the Joint Applicants
with a fair opportunity to recover merger costs through merger savings while
truly holding ratepayers harmless should merger savings not materialize. It also
guards against ratepayers incurring merger costs only to the extent the costs
are justified by merger benefits which accrue to regulated services.

C. Accounting and Reporting Requirements

1. Positions of the Parties

Common costs must be allocated between noncompetitive, potentially competitive,
and non-regulated businesses; between regulated operating companies (Sierra
Pacific and Nevada Power); between products (electric, gas and water); between
ratemaking jurisdictions (FERC, Nevada and California) and between services

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(transmission, distribution and generation). The Joint Applicants anticipate
implementing common cost allocations throughout the merger process in at least
three stages. Mary Simmons, Controller for Sierra Pacific Power Company,
testified that the allocation methodology presented in the merger filing had to
be robust and flexible enough to accommodate the full transition process. (Ex.
60, p. 6) The Joint Applicants plan to establish an automated process that will
allocate costs directly to each category. The reporting capabilities of the
financial data warehouse or general ledger system can then put these blocks back
together for reporting to various jurisdictions, reporting by operating company,
reporting by product or whatever configuration is needed. Currently, Sierra
Pacific uses location codes to indicate common costs to be allocated. Unless a
new general ledger system is implemented prior to the merger, the Joint
Applicants anticipate location codes or some other code will continue to be used
to code common costs and to trigger the automated allocation when monthly
processing occurs. (Ex. 60, pp. 9-10)

The Joint Applicants have not decided at this point whether they will use Nevada
Power's or Sierra Pacific's accounting system after the merger is consummated,
or whether to use a hybrid of the two systems, or whether to purchase an
entirely new system. The implementation of a new accounting system could take
anywhere from 6 to 12 months or more. Sierra Pacific will use its current system
immediately following the merger as will Nevada Power, and then allocations
between the companies would be done as they are today. (Tr. at 2987.)

Finally, the Joint Applicants continue to support the objectives pertaining to
shared corporate services as provided for in the rulemaking (Docket No. 97-5034)
for affiliate services and will incorporate mandated requirements into
allocation methodologies for common services. (Ex. 60, p. 10) However, the
affiliate rules (Docket No. 97-5034) will apply only to affiliates providing
competitive electric services as they interact to the distribution utility.
Thus, it is necessary for additional requirements to address account reporting
requirements for all other services and entities to be included within the
holding company structure.

Mr. Greedy, testifying for the Staff, stated that there is a potential problem
of shifting costs from competitive businesses to noncompetitive businesses.
Staff is concerned about its ability to audit costs between holding company
affiliates. Currently, there are no specific reports or procedures for getting
this information to Staff. Mr. Greedy notes that a holding company is not under
the jurisdiction of the Commission and therefore the holding company may have no
obligation to give the Commission access to any information regarding the
transactions and activities of the holding company. (Ex. 33, p. 12) Mr. Greedy
argues that the merger would increase complications with respect to the holding
company structure because Nevada Power Company and its subsidiaries will become
a wholly-owned subsidiary of Sierra Pacific Resources. Adding Nevada Power
Company and its subsidiaries will add complications to the holding company
structure because there will be additional record-keeping with additional
allocations necessary for presentations. (Ex. 33. Pp. 18-19)

Mr. Greedy recommends that the Commission order, as a condition of the merger, a
clear separation between regulated and non-regulated operations. No services or
transactions should occur between regulated and non-regulated operations without
a Commission-approved contract. (Ex. 33, p. 14.) Mr. Greedy also recommends that
the Commission order the Joint Applicants to present data as illustrated in
Exhibit 33, Attachment MLG-07. Additionally, Mr. Greedy provides recommendations
concerning documentation by way of a Master Services Agreement and an accounting
system review. (Ex 33, p. 16) A Master Services Agreement would describe rules
for transactions among affiliates.

In rebuttal testimony, Ms. Simmons testified that the Joint Applicants are
concerned about adding complexity to the system. Much of their concern revolves

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around how often the information would need to be provided. Ms. Simmons argued
that summary information could be provided as a check versus the detailed
schedules proposed by Mr. Greedy. The Joint Applicants would prefer to use the
systems they currently have to pull out the information that Staff desires on an
interim basis until the actual accounting system for the merged companies is in
place. (Tr. at 2995.)

2. Commission Decision

The Commission finds that the Joint Applicants were unable to provide much
detail on the mechanics of the accounting systems after the merger. Thus, the
Commission finds that it is appropriate to accept Mr. Greedy's recommendations.
Therefore, as a condition of merger approval, the Commission finds that the
Joint Applicants shall:

1. maintain a clear separation between regulated and non-regulated operations;

2. present data as illustrated in Exhibit 33, Attachment MLG-07;

3. file a Master Services Agreement for approval by the Commission that
applies to those services not covered by the affiliate rule adopted in
Docket No. 97-5034;

4. not use a single accounting system until such time as a report on account
numbering to be used is filed with the Commission and a detailed and
comprehensive plan for using a single accounting system is filed with the
Commission and the Master Services Agreement is in effect;

5. after consultation with Staff, file a plan with the Commission to routinely
provide electronic access to all Joint Applicants' recorded accounting
data; and

6. file an acknowledgment that it shall provide Staff and the UCA full and
complete access to all books and records of Sierra Pacific Resources,
Sierra Pacific Power Company, and Nevada Power Company to enable these
parties and the Commission to fulfill their statutory obligations.

Should the Joint Applicants, Staff and the UCA wish to develop an alternative
reporting mechanism for the interim to satisfy Staff's concerns, they are
encouraged to do so. Likewise, Joint Applicants are encouraged to confer with
Staff and the UCA during development of the merged entity's new accounting
system to assure it has the capacity to provide the information required for
reporting purposes.

D. Two County Tax Exempt Bonds

1. Positions of the Parties

Nevada Power has approximately $541 million of Tax-exempt Industrial Development
Revenue Bonds outstanding. The Internal Revenue Code of 1954, as amended, grants
tax-exempt status on the interest on state and local Industrial Development
Revenue Bonds which are to be used to provide facilities for the "local
furnishing" of electric energy. That term is defined in the Income Tax
Regulations as property which is part of a system providing service to the
general populace of no more than two contiguous counties. The amount eligible
for financing through these tax-exempt bonds can include an amount comprising
both expenditures for the prior 12 months as well as anticipated expenditures
for facilities for the next three-year period of time. The interest rates
historically have been two hundred basis points lower for tax-exempt debt versus
taxable debt. (Ex. 24, p. 9)

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Mr. DeWeese provided testimony for the Staff that suggests the merger between
Nevada Power and Sierra Pacific may adversely affect the exclusion from gross
income of interest on local furnishing bonds that have been issued for the
benefit of Nevada Power. In the event that Nevada Power loses its tax-exempt
status under the two county rule, the company would incur annual additional
interest expense of at least $8 million. If the company does not get a favorable
Bond Counsel Opinion or IRS Letter Ruling, Staff believes it would cost the
company at least $80 million, if not more, to refinance the tax-exempt
securities over a ten-year period. (Ex.24, pp. 12-13)

Staff recommends that the Commission order the Joint Applicants to seek an
Internal Revenue Service Private Letter Ruling that the merger will not
adversely affect the exclusion from gross income of interest on the local
furnishing bonds issued by Nevada Power as a compliance item. (Ex 24, p. 2)

A final opinion from Nevada Power's bond counsel is required prior to the merger
being consummated. In order to maintain the tax-exempt status of the bonds,
Nevada Power's Bond Counsel must find that there will be no power exchanged
between the two entities and that they will maintain separate rates. Any
facilities purchased with tax-exempt bonds cannot be shared between the two
entities if the tax-exempt status of the bonds is to be maintained. (See ex. 58,
p.2, i-v.) Therefore, moving any facilities that were funded by the tax-exempt
bonds to competitive affiliates may require partial refunding of a bond issue.
(Tr. at 2864.)

In rebuttal testimony, Mr. Schmalz, Director of Treasury for Nevada Power,
testified that seeking an IRS Letter Ruling would not provide any benefits and
could possibly be harmful to the company and its customers. The company's bond
counsel, Chapman and Cutler, has advised the company that during the time the
Letter Ruling request is pending with the IRS, the company would be unable to
obtain a favorable opinion from any bond counsel stating that the interest paid
on the bonds is not to be included in the gross income of the bondholders. (Ex
81, p. 3-4) The IRS letter ruling process often takes up to a year or more to
reach conclusion and any change in company operations within the period would
invalidate the letter ruling. (Tr. at 2856.)

In lieu of an IRS letter ruling, the Joint Applicants have agreed to hold
ratepayers harmless with respect to any increased net costs from the loss of Two
County tax-exempt status resulting from the consummation of the merger (Ex. 59).

2. Commission Decision

The Commission accepts the Joint Applicants' proposal to hold ratepayers
harmless with respect to any increased net costs from the loss of Two County
tax-exempt status resulting from the merger, and therefore finds that an IRS
Private Letter Ruling is not necessary for final approval of the merger.
However, the Commission also notes that Bond Counsel's August 8, 1998 opinion
states that it would not be permissible to use common personnel for the
day-to-day operations of the systems, such as common billing and customer
service personnel (since the company must transfer these operations to
affiliates as required by Chapter 482, the bond counsel's concerns are
mitigated). The Commission finds that this could have effects on the potential
synergies of using customer service personnel, etc. between the two companies.
The Joint Applicants will have to look carefully at this restriction as certain
synergies may not be possible due to the restrictions of maintaining the
tax-exempt funding under the two county rule. (Tr. at 2866)

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IV. Effect on Existing Contracts

A. Determination of the Effect of the Merger on Purchased Power Contracts

1. Positions of the Parties

Mr. Niggli testified that the Joint Applicants have no final plans as to how to
deal with their QF contracts. (Tr. at 66-67.) However, the Joint Applicants
propose that purchased power costs remain in bundled rates as they are today.
(Tr. at 164.) The Joint Applicants' preferred way to deal with above-market QF
contracts is to require aggregators to purchase from a portfolio of purchased
power contracts. In any event, the Joint Applicants state that they intend to
fulfill all of the obligations of their purchased power contracts, however, they
could not specify how they will meet those obligations as a merged entity in a
restructured environment. (Tr. at 48.)

Mr. Campbell, testifying on behalf of Las Vegas Cogeneration, testified that the
merger itself would have little or no impact on QF contracts, however, Mr.
Campbell raised concerns about having the contracts assigned to an affiliate of
the merged company. His concerns stem from unknown factors such as the
affiliate's creditworthiness, assets and liabilities, and relationship to the
parent company. (Tr. at 827.)

Mr. Schoenbeck, testifying on behalf of the Nevada Independent Energy Coalition,
testified that the companies' QF contracts must be assigned as part of the
merger. In order for the contracts to be assigned, the parties to the contract
must give written consent to assign the contracts to a third party. Mr.
Schoenbeck also is unclear how the merged entity plans on dealing with the QF
contracts, however, he states that the merger itself should have very little
impact on the contracts. Given that there is no clear statement of intent of how
purchased power contracts will be treated given the proposed divestiture of
generation plants, Mr. Schoenbeck recommends that the Commission provide certain
assurances to the QFs. (Tr. at 892.) In order to get the contract holders to
agree to assignment of the contracts, Mr. Schoenbeck contends that the
Commission should require that the contractual prices, terms and conditions of
the QF purchased power agreements be honored by the merged entity and that
payments made pursuant to the terms and conditions of the QF purchased power
agreements continue to be collected from ratepayers through charges comparable
to the manner in which these costs are being recovered today. (Ex. 25, p. 6.)

Mr. Burton, testifying on behalf of the Mirage/MGM, argued that the Commission
should be careful not to allow the Joint Applicants to decide how QF contracts
should be treated once generation markets are opened to competition. Mr. Burton
believes that any above-market QF contract costs should be evaluated by the
Commission and netted against any potential gains on the sale of assets. (Tr. at
516.) The Joint Applicants' filing provides little information on the treatment
of recoverable stranded costs. However, the Joint Applicants' proposal to let QF
contracts run their course is a premature determination of the treatment of
recoverable stranded costs by the companies.

2. Commission Decision

The Commission finds that the Joint Applicants' proposal would result in
customers taking the entire risk of above-market QF contracts costs. As noted
above, it is not appropriate to use the merger filing to pre-determine any
recoverable stranded cost issues. Any formulas for accounting for stranded
investment costs should be adopted only by order of the Commission after careful
review of the requirements of NRS 704.983.

As for the conditions requested by QFs, the Commission does not believe it
necessary to include them in the merger approval order. The Commission presumes

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that the Joint Applicants will act consistently with their contracts with the
QFs. No one has suggested that the merger transaction itself will violate those
contracts. The Commission will of course entertain complaints from QFs alleging
that the Joint Applicants are acting inconsistently with their contracts. The
Commission also presumes that the Joint Applicants will act consistently with
all of their other purchased power contracts.

B. Determination of the Effect of the Merger on Large Customer Contracts

1. Positions of the Parties

The Joint Applicants testified that they intend to meet the terms and conditions
of all customers' contracts following the divestiture and merger. However, the
application does not define how power would be repurchased from divested
generation assets. Mr. Oldham testified that the merged company wanted to
continue to serve customers taking service under its GS-4C and GS-5T tariffs,
but did not specify how it will do so. (Tr. at 262-267.) He further testified
that Sierra has not made final determinations concerning how it will honor the
contracts it has with large customers because it does not know what rules will
prevail in the restructured environment. (Tr. at 396.) Mr. Davis testified that
all contracts NPC currently holds will be assumed by the new "Nevada Power Co."
(Tr. at 454) but could not say whether the merged company will be in a position
to fulfill certain obligations now embodied in contracts with the Colorado River
Commission once the merger is consummated and retail competition has begun (Tr.
at 464-65, 470-71). The Joint Applicants' failure to present a business plan
that outlines the lines of business the companies plan to enter in a
restructured market gives rise to the parties' concerns as to how the Joint
Applicants will meet their contractual obligations after the divestiture and
Nevada markets are opened to retail competition. Ms. Thomas testified that even
with the business plan, the Joint Applicants must address how they intend to
handle existing contractual obligations. (Tr. at 1685.)

Ms. Thomas noted that large customers are critical to the Nevada economy,
however, they are also sophisticated customers who entered into the power supply
contracts knowing the possibility of retail competition in the provision of
electric services. Many of these contracts have severe termination penalties.
(Tr. at 1619.) Thus, Ms. Thomas testified that an open season hold harmless
provision for supply contracts should contain provisions so that termination
penalties are not enforced during the open season. However, Ms. Thomas argued
that this is not as much a merger issue as it is a restructuring issue and
should be addressed in the companies' potentially competitive/noncompetitive
service filings under Docket No. 97-8001. (Tr. at 1723.) Ms. Thomas recommends
that the Commission set up a proceeding in which to determine how the companies'
power supply contracts to large customers will be addressed after restructuring.
This would likely be handled in the companies' compliance filings. (Tr. at
1613.)

2. Commission Decision

The Commission agrees with Ms. Thomas that the contracts issue should not be
resolved in this proceeding because the merger proposal, in and of itself, does
not affect any large customer contract. The Commission recognizes, however, that
structural changes, including those mandated by the Legislature (such as the
requirement in NRS 704.978(1) that potentially competitive and noncompetitive
services be provided by separate affiliates), those proposed by the utilities
(such as whether to provide potentially competitive services under competition)
and those mandated by the Commission (such as whether to allow one or both
utilities to form affiliates to provide one or more potentially competitive
services), may have an effect on large customer contracts. This area raises
legal questions not directly addressed by the Legislature, such as whether a new
potentially competitive service affiliate of an incumbent utility should be able

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to start in the competitive market with customer contracts obtained in the
pre-competitive era. The Commission therefore intends to initiate an
investigation to explore this issue in the near future, and will issue a
procedural order outlining the issues to be considered.

V. Effect on Quality of Service

A. Electric Service Reliability

1. Positions of the Parties

The Joint Applicants' filing provides statements that electric service
reliability will not be harmed as a result of the merger. The direct testimony
of Mr. Oldham states that the merger will have no adverse effect on the quality
of service provided to customers (Ex. 11, p. 3) and likewise, the direct
testimony of Mr. Davis states the quality of service will not be adversely
affected by the merger, and will likely improve (Ex.12, p. 7). Mr. Davis
testified that the Joint Applicants have always provided a high degree of
reliability and customer service and are committed to continuing to provide and
improve the high degree of service and reliability. (Ex. 12, p. 7) Mr. Malquist
testified that the Joint Applicants intend to look at the best practices of both
companies to achieve higher quality of service. (Tr. 1803)

To assure that quality of service will not be degraded as a result of the
merger, the Joint Applicants will collect outage data on their distribution and
transmission system that will be compared to average historical data. The data
will reflect outage frequency and duration and will be reported annually with
the yearly earnings report. The Joint Applicants will use Sierra Pacific's
outage data collection methodology to track and report the information needed to
meet this commitment. (Ex 12, pp. 7-8) Although the Joint Applicants did not
propose any quality of service objectives or standards in the merger
application, they are confident that such objectives and standards can be
developed with Staff, provided that the data required is readily available and
is relatively simple to utilize in measurement. (Tr. at 2056.)

Mr. Winterfeld, Assistant General Manager of Power Marketing for Deseret
Generation and Transmission Cooperative, argued that the Joint Applicants'
commitment that the merger will not adversely affect quality of service is
counter-intuitive to the trend of experience in rural service areas and does not
sufficiently address the factors included by customers in expectation of quality
service. (Ex. 67, p. 10)

Mr. Candelaria, testifying on behalf of Staff, argues that the Commission should
invoke conditions on the Joint Applicants to assure that the level of electric
service quality will not be adversely affected by the merger. Staff believes
that, as a condition of allowing the merger to go forward, the Commission should
order the Joint Applicants to develop a methodology for comparing the electric
service quality provided to the Joint Applicants' customers before the merger to
that provided after the merger. The methodology should provide the Commission
with a means of determining whether or not the merged company's customers have
been adversely affected by the merger. (Ex. 68, p. 2)

Staff contends that the Joint Applicants' service quality proposal is deficient
in that the Joint Applicants have not explained how they would compare outage
data of the merged company with the historical data of the two separate
companies. Mr. Candelaria testified that in order to determine the impact of the
merger on electric service quality, one would need to adopt performance measures
that would adequately reflect the level of electric service quality that exists
in each company's service territories. Once acceptable performance measures are
adopted, electric service quality performance data (baseline data) would need to

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be developed from historical data that predates the merger. Mr. Candelaria then
suggests that the baseline performance data would be used as a benchmark against
post-merger electric service quality performance. Therefore, the impact of the
merger on the level of electric service quality could be demonstrated by
periodic comparisons of post-merger performance data to pre-merger performance
data. (Ex. 68, pp. 3-4)

Staff recommends use of the SAIDI, SAIFI, ASAI, CAIFI and CAIDI indices to
measure electric service quality of the merged company, however, Staff
recognizes that Nevada Power cannot currently calculate these indices. Staff
recommends these indices because they are commonly-used performance measures in
the electric industry, Sierra's outage reporting program and Nevada Power's
proposed distribution dispatch management system (DDMS) system will be able to
calculate these performance measures, and Staff believes that these measures can
provide the Commission with useful information for assessing the level of
electric service reliability of the merged company. (Ex. 68, p. 5.)

Staff's recommendations include that the Commission order the Joint Applicants
to work with Staff and other parties to develop electric service quality
performance benchmarks from historical data that adequately reflect the electric
service quality of the Joint Applicants' electric systems. The benchmarks should
be established for each district as they exist today and the Joint Applicants
should be required to file their proposed performance benchmarks and methodology
for calculating the benchmarks within sixty days after the Commission issues its
order on the merger. Once the companies are merged, the Commission should order
the Joint Applicants to submit electric service quality performance data by
district to the Commission on a quarterly basis so that a comparison of the
performance data to the benchmark data can be made. Finally, in the event that
the merged company fails to provide a quality of service level equal to that
level before the merger, the Commission should consider penalties in specific
show cause proceedings or expense disallowance or reductions to rate base in the
context of general rate proceedings. (Ex. 68, p. 10)

Ms. Galati, Vice President of Distribution for Nevada Power, provided rebuttal
testimony contending that while the Joint Applicants do not quarrel with many of
Staff's recommendations, the Joint Applicants do have concerns about the details
of and potential implementation of those recommendations. (Ex. 82, p. 1.)

2. Commission Decision

The Commission is aware that retail competition and the Commission's ratemaking
treatment as outlined in this order may introduce new pressures on industry
participants. Regulatory monitoring will be necessary to assure that these
pressures do not adversely affect safety and reliability. It is possible that to
this end, the Commission will need to create new electric service quality
performance measures. The Commission intends to address this issue in the
context of its investigations and rulemakings concerning the implementation of
Chapter 482. In the meantime, the Commission urges the Joint Applicants to work
with Staff and other parties to develop electric service quality performance
benchmarks from historical data that adequately reflect the electric service
quality of the companies' electric systems.

B. Quality of Customer Service

1. Positions of the Parties

Mr. Hackman, Manager of the Consumer Complaint Resolution Division for the
Commission, addressed customer service issues arising from the merger. Mr.
Hackman recognized that the Commission has deemed customer service a potentially
competitive service under Chapter 482 of the 1997 Legislature and that market
forces will be replacing much of the traditional regulation of the service once

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the electric markets in Nevada are opened to alternative sellers. However, Staff
contends until the evolution to competition is complete, the Commission has the
duty to continue to see that customers are protected and that safe, reliable and
timely utility services are provided. (Ex. 69, p. 2.)

The Joint Applicants state in their application that customer service levels
will be maintained or improved as a result of the merger. At the same time the
companies are proposing reducing staffing levels (64 customer service personnel)
in the customer service area. Thus, Staff is concerned that customer service may
be threatened by the proposed merger. (Tr. at 2387.) To address adverse affects
of the merger on customer service, Staff proposes that the companies be held to
certain guarantees and benchmarks to ensure that current customer service levels
will be maintained. Mr. Hackman outlined several specific recommendations in his
testimony. Staff is also recommending that periodic surveys continue to be taken
to gauge customer satisfaction and that the results of the surveys be submitted
to Staff. (Ex. 69, p. 4.)

2. Commission Decision

The Commission is concerned that merger savings projected by the Joint
Applicants assumed significant reductions in customer service personnel. These
reductions, in combination with increasing response time to Consumer Complaint
Resolution Division inquiries, may lead to decreases in the quality of customer
service. The Commission therefore finds that a sufficient basis exists to
condition the merger approval on special measures to monitor customer service
levels. For the period between consummation of the merger and the start of
retail open access in Nevada, the Joint Applicants shall provide information, as
described below, to the Commission's Consumer Complaint Resolution Division
(Division) that will enable the Division to assess whether customer service
levels are being maintained by the merged entity. Assuming the Joint Applicants
continue to provide noncompetitive services once competition begins, the Joint
Applicants shall continue to provide information on customer service levels
specific to those noncompetitive services after competition begins, until the
Commission determines that such information reports no longer are necessary.

Ms. Hollins, Director of Customer Service for Nevada Power Company, testified
that Nevada Power's existing Customer Satisfaction survey was not developed for
use by the Commission or for public disclosure. The existing survey was
voluntarily instituted as part of Nevada Power's incentive compensation program
for management and professional employees, partly as a result of the
Commission's encouragement in its Opinion and Order on Nevada Power's 1991
general rate case (Docket No. 91-5055). (Ex 83, pp. 9-10.) Nevada Power's
Customer Satisfaction Surveys acquire data on timeliness of response, knowledge
of employees, home energy audits, and service reliability. The survey has been
conducted for several years and the results of such surveys are available and
could be distributed to the Consumer Division. (Tr. at 2946.)

The Commission finds that past survey results and the results of future surveys
can be utilized to provide a measure of customer service quality by the Division
during the period between the consummation of the merger and the start of
competition for potentially competitive services in Nevada. Therefore, the
Commission finds that as a condition to approval of the merger, the Joint
Applicants shall provide the Division with the historical results and survey
questions of each company's customer satisfaction surveys as requested by the
Division. The Joint Applicants shall also provide the Division with the results
and survey questions of the customer satisfaction surveys conducted from the
final consummation of the merger until such time as the Nevada electric markets
are opened to competition for potentially competitive services. If the Division
finds that customer service quality has diminished as a result of the merger,
the Division shall file such information with the Commission and the Commission
shall consider appropriate penalties.

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Once competition begins, customer service functions applicable to potentially
competitive services will themselves be potentially competitive services, due to
prior Commission order. The Commission expects that the combination of
competitive pressures on those who provide these services, plus the application
of the Commission's licensing and consumer protection rules, will provide the
incentive for the alternative sellers to provide superior levels of customer
service. Similarly, the consumer bill of rights, applicable to the providers of
last resort, should work to maintain appropriate service levels. The customer
service indices proposed by Staff may be of assistance to the Commission in
reviewing whether its expectations on customer service levels are being met. The
Commission therefore would welcome proposals by the Staff or other parties to
make use of these indices in that context.

VI. Effect on Commission Jurisdiction

A. Positions of the Parties

The Commission currently has jurisdiction over the rates, terms and conditions
applicable to bundled retail service, retail sales of unbundled generation and
the certification and resource planning for generation and transmission. Chapter
482, 1997 Legislature envisions that the Commission will retain the authority to
address market power in the provision of potentially competitive services. Once
potentially competitive service markets are opened to competition, the
Commission will retain its cost of service based rate setting jurisdiction over
noncompetitive services. The Commission will also retain licensing and limited
rate setting authority for all potentially competitive services.

Mr. Russell, testifying on behalf of Staff, testified that the merger will
affect the Commission's jurisdiction in several ways. First, Mr. Russell states
that if, after the merger and divestiture, the new company is purchased by a
large multi-state company, the Commission would have to contend with a
vertically integrated utility possibly operating several other related
businesses. Regulating and determining the appropriate ROR on transmission and
distribution assets owned by such an enterprise would become increasingly
complex for the Commission. (Ex. 26, p. 11.) Mr. Russell also brings up the
possibility that the merger could have an effect on the native load priorities
embodied in the FERC's pro forma open access transmission tariffs (OATT). The
merger coupled with the OATT may enable the Joint Applicants to increase their
ability to favor affiliates providing potentially competitive services over
competing suppliers of those services. (Ex 26, p. 11.) Finally, Nevada Power is
not now organized as a holding company but will become a subsidiary of a
(presumably exempt) holding company as a result of the merger. Mr. Russell
testified that this fact alone can be expected to complicate regulation of
Nevada Power and potentially open up real or claimed regulatory gaps. For
example, the Commission may in the future be confronted with claims that its
jurisdiction does not extend to the holding company or to its unregulated
affiliates. Or the Joint Applicants could assert that the SEC has jurisdiction
over cost allocations now controlled by FERC or this Commission. (Ex. 26, p. 12)

B. Commission Decision

The Commission finds that the merger could potentially have negative effects on
its jurisdiction over the new company. However, some of Mr. Russell's concerns
are as a result of a subsequent merger of the new company with a large
multi-state company. The Commission finds that if such an event were to occur,
the proper forum to address the jurisdictional problems would be in that filing.
Furthermore, the Commission finds that Mr. Russell's concerns help to illuminate
the need for the additional accounting requirements imposed on the Joint
Applicants as set forth in the Commission's decision in the previous section.

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The most significant issue before the Commission at this time is whether the
merged entity could or would take any action to become a registered holding
company under the Public Utility Holding Company Act (PUHCA) and thereby trigger
a preemption of state review of certain company transactions. Under questioning,
Mr. Oldham reported it was not the intent of the Joint Applicants to take any
action to become a registered holding company. Mr. Oldham did not know if it
would cause problems if the Commission conditioned approval of the merger on the
companies taking no action that would cause the exempt holding company to become
a registered holding company under PUHCA.

It is difficult to imagine what problems, if any, would be created by the
imposition of such a condition as part of its conditioned merger approval. Since
federal preemption of Commission authority to review certain affiliate
transactions of a registered holding company would constitute a serious problem,
the Commission believes it is in the public interest to impose the condition
discussed above.

VII. Other Authorization Requested

A. Transfer of Certificate of Public Convenience and Necessity

In order to determine whether the Certificate of Public Convenience and
Necessity presently held by the existing Nevada Power Company should be
transferred to the new Nevada Power Co., the Commission must consider, pursuant
to NRS 704.410(5),

(a) the utility service performed by the transferor and the proposed utility
service of the transferee,

(b) other authorized utility services in the territory for which the transfer
is sought, and

(c) whether the transferee is fit, willing and able to perform the services of
a public utility and whether the proposed operation will be consistent with
the legislative policies set forth in NRS 704.005 to 704.751, inclusive.

NRS 704.410(5)(a) The Commission has considered the utility services provided to
date by the existing Nevada Power Company as well as the utility services to be
provided by the post-merger Nevada Power Co. Nevada Power Co. will be restricted
by law to performing only noncompetitive utility services; it must, pursuant to
NRS 704.978 and 704.980, provide any and all potentially competitive services
through one or more affiliates. As discussed during the course of this
proceeding, Sierra Pacific Power Company and Nevada Power Company plan to
evaluate and adopt the best practices of each utility.

NRS 704.410(5)(b) Sierra Pacific Power Company and Nevada Power Company
presently operate in exclusive certificated service territories; there are no
other utilities presently authorized to provide electric services in either
territory. The Commission finds that it has satisfied its obligation to take any
other authorized utility services into account in making its decision in this
matter.

NRS 704.410(5)(c) The Commission must also consider whether Nevada Power Co. is
fit, willing and able to perform the services of a public utility and whether
the proposed operation will be consistent with the legislative policies set
forth in NRS 704.005 to 704.751, inclusive. Both Sierra Pacific Power Company
and Nevada Power Company have successfully operated as regulated public
utilities in their respective jurisdictions for years. According to the evidence
presented, as sister subsidiaries of Sierra Pacific Resources, they intend to
compare each other's operations in order to determine whether current methods

56
<PAGE>
and procedures should be replaced by better ones. The Commission anticipates
that the service which Nevada Power Co. will provide will not be any lesser in
quality than that presently provided by Nevada Power Company. The Commission
concludes that Nevada Power Co. is fit, willing and able to perform the services
of a public utility. The proposed operation of Nevada Power Co. will be
consistent with the legislative policies set forth in NRS 704.005 to 704.751,
inclusive.

B. Cancellation and Conversion of Common Stock

NRS 704.324 With respect to the proposed cancellation and conversion of common
stock, the Commission must determine, pursuant to NRS 704.324(5), whether the
Joint Applicants' request is for some lawful object, within the corporate
purposes of the Joint Applicants and compatible with the public interest,
necessary or appropriate for or consistent with the proper performance of
service by Nevada Power Co. as a public utility, and whether it will impair the
ability to perform that service. Provided that all the terms and conditions of
this Order are met, the merger of Sierra Pacific Resources and Nevada Power
Company will be in the public interest. The Commission can conclude that the
cancellation and conversion of common stock, in the context of this proposed
merger, is, in fact, a lawful objective within the corporate purposes of Sierra
Pacific Resources and Nevada Power Company. In order for the two utility
subsidiaries to function, the holding company must have the ability to issue
securities and assume obligations. Therefore, the request is within the
corporate purposes of the Joint Applicants and compatible with the public
interest, and necessary or appropriate for or consistent with the proper
performance of service as public utilities. The cancellation and conversion of
common stock will not impair the ability of either Sierra Pacific Resources
(through Sierra Pacific Power Company) or the new Nevada Power Co. to perform
the services of public utilities.

Therefore, based on the foregoing findings of fact and conclusions of law, it is
hereby ORDERED that:

1. The joint application of Sierra Pacific Resources, Sierra Pacific Power
Company, and Nevada Power Company for approval of an agreement to merge,
for authorization to cancel and convert common stock of Nevada Power
Company to common stock of Sierra Pacific Resources, and for the transfer
of the Certificate of Public Convenience and Necessity held by Nevada Power
Company to the newly-formed Nevada Power Co., is CONDITIONALLY APPROVED and
approved only to the extent set forth in this Compliance Order; in all
other respects, the joint application is DENIED.

2. Before the merger shall be considered fully and finally approved, Nevada
Power Company and Sierra Pacific Power Company shall take the following
actions, consistent with the terms and conditions of this Compliance Order:

(a) file individual rate cases to establish actual revenue requirements
pursuant to NRS 704.986 and the regulations adopted by this Commission,
which revenue requirements shall be frozen for a period of three years,

(b) unbundle costs by functionalizing and allocating costs of services as
ordered in Docket Nos. 97-11018 and 97-11028,

(c) divest generation assets as specified in a plan of divestiture filed with
the Commission, including the elements set forth in the Commissions
decision above and including a representation that the Joint Applicants
intend to implement the plan as filed in good faith,

(d) submit, pursuant to NRS 704.983 and Commission regulation, an application
to recover recoverable stranded costs for those services determined to be
potentially competitive,

57
<PAGE>
(e) agree to allocate proceeds from the sale of generating assets as specified
above,

(f) agree to abide by the ratemaking treatment for costs and savings associated
with the merger, which is specified above,

(g) agree to abide by the accounting and reporting requirements specified
above,

(h) agree to hold ratepayers harmless with respect to any loss by NPC of its
two-county tax-exempt status which stems from this merger,

(i) work with Staff to develop benchmarks for electric service quality as
specified above,

(j) agree to provide to the Division of Consumer Complaint Resolution, as
requested by the Division, all historical results and survey questions
which relate to customer service, and

(k) agree to refrain from taking any action to become a registered holding
company under the Public Utility Holding Company Act, and

(l) file a generation aggregation tariff and a proposal for an independent
system administrator with the Federal Energy Regulatory Commission which
are consistent with the requirements set forth above.

3. This Compliance Order does not constitute authorization to merge. Failure
on the part of the Joint Applicants to comply with the terms of this
Compliance Order may cause this Compliance Order to be vacated and the
underlying Joint Application dismissed, unless the Commission otherwise
orders.

4. The Commission retains jurisdiction for the purpose of correcting any
errors which may have occurred in the drafting or issuance of this
Compliance Order.

By the Commission,

JUDY M. SHELDREW, Chairman

LUCY A. STEWART, Commissioner

DONALD L. SODERBERG, Commissioner

Attest: JEANNE REYNOLDS, Commission Secretary

Dated: 1/4/99 Carson City, Nevada

58
<PAGE>
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA

Docket No. 98-7023

In Re Joint Application of NEVADA POWER

COMPANY, SIERRA PACIFIC POWER

COMPANY, and SIERRA PACIFIC RESOURCES

for approval of agreement and plan of merger.

- ------------------------------------------

At a general session of the Public Utilities Commission of Nevada, held at its
offices on January 29, 1999.

PRESENT:

Chairman Judy M. Sheldrew

Commissioner Donald L. Soderberg

Commission Secretary Jeanne Reynolds

ORDER CLARIFYING COMPLIANCE ORDER

The Public Utilities Commission of Nevada ("Commission") makes the following
findings:
1. On January 4, 1999, the Commission entered a Compliance Order in the
above-captioned docket.
2. On January 11, 1999, the Joint Applicants filed a motion for clarification
of portions of the Compliance Order and for an order shortening time. In
this motion, the Joint Applicants have requested that the Commission (a)
clarify portions of the Compliance Order, (b) rule on this motion for
clarification on or before January 15, 1999, and (c) stay the running of
the time period for filing petitions pursuant to NAC 703.801 while
considering this motion or, in the alternative, extend the date for filing
such petitions beyond January 19, 1999 so that any necessary petitions can
be filed after the Commission has ruled on this motion for clarification.

<PAGE>
3. On January 13, 1999 the Commission issued an Order which denied the Joint
Applicants' request to shorten time for responses, established the date of
January 21, 1999 for filing responses, and established the date of January
25, 1999 for any reply the Joint Applicants needed to file.
4. Responses to the Joint Applicant's motion were filed by the Regulatory
Operations Staff of the Commission, the Utility Consumers Advocate, and the
Southern Nevada Water Authority. The Joint Applicants filed a reply to
these responses.
5. Upon consideration of the motion and responses filed thereto, the
Commission believes that clarification of portions of its Compliance Order
are warranted. Accordingly, the Compliance Order should be modified and/or
clarified to the extent set forth in this order. The Commission will not
address at this time the Joint Applicants' request for any extension of
time (past January 19, 1999) in which to file petitions pursuant to NAC
703.801. If any party of record files such a petition, that party will bear
the burden of demonstrating that the petition could not have been filed on
January 19, 1999, or that some other reason exists for its having been
filed after January 19, 1999.
6. The Commission's Compliance Order of January 4, 1999 is clarified as
follows:

SECTION II(C)(2(b) fourth paragraph, pp. 87-88:

The Commission understands the Joint Applicants' desire that shareholders share
in the benefits of a successful divestiture process beyond simply recovering
those costs determined to be recoverable stranded costs. Mr. Oldham repeatedly
spoke of "incentives" to encourage the development of good practices in utility
operations. However, the Commission believes management and shareholders also
should face incentives to minimize stranded costs. Therefore, if the after-tax
gain on the sale of the generation assets is greater than the Joint Applicants'
recoverable stranded costs, taking into consideration statutory considerations
enumerated in NRS 704.983, the remaining portion shall be available to FIRST buy
down the GENERATION RELATED goodwill acquisition premium AND IF ANY PORTION
REMAINS, IT SHALL BE AVAILABLE TO BUY DOWN THE NONCOMPETITIVE GOODWILL
ACQUISITION PREMIUM in the manner set forth in Section III of this opinion. The
Commission therefore encourages the utilities to aggressively seek to reduce
their recoverable costs so as to increase the remainder of the gain available to
buy down the goodwill acquisition premium. In the event that the Commission
determines that there are no material recoverable costs due to the Joint
Applicants pursuant to NRS 704.983, the Commission shall open a proceeding in
order to determine the appropriate sharing of the gain on the sale of the assets
between ratepayers and shareholders.

IF THE AFTER TAX GAIN FROM THE SALE OF THE GENERATION ASSETS IS NOT SUFFICIENT
TO RECOVER THE GOODWILL ALLOCATED TO THOSE ASSETS, TAKING INTO CONSIDERATION THE
STATUTORY CONSIDERATIONS ENUMERATED IN NRS 704.983, THE JOINT APPLICANTS MAY
INCLUDE IN THE GENERAL RATE CASE (AS SET FORTH IN SECTION III) A REQUEST TO
RECOVER THE GOODWILL ALLOCABLE TO GENERATION ASSETS UPON A SHOWING THAT THE
DIVESTITURE OF THE GENERATION ASSETS RESULTED IN A MARKET FOR GENERATION
SERVICES THAT PRODUCED MARKET PRICES THAT WERE LOWER THAN WHAT COULD HAVE BEEN
ACHIEVED OTHERWISE.

2
<PAGE>
ORDERING Paragraph 2 (c), (d) and (i):

(c) FILE a plan of divestiture with the Commission, including the elements set
forth in the Commission's decision above and including a representation that the
Joint Applicants intend to implement the plan as filed in good faith.

(d) AGREE TO submit, pursuant to NRS 704.983 and Commission regulation, an
application to recover recoverable stranded costs for those services determined
to be potentially competitive, IN ACCORDANCE WITH THE REGULATIONS ADOPTED IN
DOCKET NO. 97-8001 CONCERNING SUCH FILING, WHICH INCLUDES THE VALUATION OF THE
DIVESTED GENERATION ASSETS,

(i) AGREE TO work with Staff to develop benchmarks for electric service quality
as specified above,

Therefore, based on the foregoing, it is hereby ORDERED that:

1. The Compliance Order entered in Docket No. 98-7023 is clarified and
modified only to the extent set forth above; in all other respects, the
Compliance Order remains unchanged.

2. The Commission retains jurisdiction for the purpose of correcting any
errors which may have occurred in the drafting or issuance of this Order
Clarifying Compliance Order.

By the Commission,

JUDY M. SHELDREW, Chairman

DONALD L. SODERBERG, Commissioner

Attest: JEANNE REYNOLDS, Commission Secretary

Dated: 2/1/99 Carson City, Nevada

[LETTERHEAD OF SIERRA PACIFIC RESOURCES]

William E. Peterson
Senior Vice President
General Counsel and Corporate Secretary
6100 Neil Road, P.O. Box 30150, Reno, Nevada 89520-3150
775.834.5900 o Fax: 775.834.5959 o E-Mail: [email protected]

February 10, 1999

Securities & Exchange Commission
450 5th Street, N.W.
Washington, DC 20549

Re: Sierra Pacific Resources/Nevada Power Company Merger
----------------------------------------------------

Ladies and Gentlemen:

I am Senior Vice President and General Counsel for Sierra Pacific
Resources, a Nevada corporation ("SPR") and its wholly owned subsidiary, Sierra
Pacific Power Company, a Nevada corporation (the "Company" or "SPPCo"). SPPCo is
a public utility regulated by the California Public Utilities Commission
("CPUC") and the Public Utilities Commission of Nevada ("PUCN"). SPPCo is
predominantly a Nevada utility, earning 93% of its revenues in the State of
Nevada. It's California operations are principally limited to the California
side of Lake Tahoe and consists of approximately 40 MW of load. I am licensed to
practice and actively engage in practice in all state and federal courts in
California and Nevada. The Company handles all its own regulatory work before
the CPUC and PUCN. I am the principal regulatory counsel for the Company in both
jurisdictions. I am the attorney responsible for handling all regulatory matters
pertaining to the proposed merger (the "Transaction") between Desert Merger Sub,
a wholly owned subsidiary of SPR, and Nevada Power Company ("NPC"), in which
Transaction Nevada Power will become a wholly owned subsidiary of SPR. NPC is
also a Nevada corporation, and is subject to the jurisdiction of the PUCN. SPPCo
is unaffected by the Transaction, and will remain a wholly owned subsidiary of
SPR. I am also responsible for obtaining all required state approvals for the
Transaction. SPR, Desert Merger Sub, and NPC filed an application to approve the
Transaction with the PUCN in July 1998. Although not a party to the Transaction,
SPPCo joined in that application in order to obtain PUCN approval to sell
SPPCo's generating plants rather than filing a separate docket, and then seeking
to consolidate it with the merger docket. The PUCN issued an order approving the
Transaction on January 4, 1999, and subsequently granted SPR, NPC, and SPPCo's
motion to clarify its order approving the transaction on January 29,1999.

SPR, Desert Merger Sub, SPPCo, and NPC were not required to file an
application to approve the Transaction before the CPUC under Cal. Pub. Util.
Code ss. 854 (California merger approval statute); however, as in Nevada, SPPCo
<PAGE>
Securities and Exchange Commission
February 10
Page 2

is required to file an application to approve the proposed sale of its
generating assets under Cal. Pub. Util. Code ss. 851.

The California merger approval statute (Cal. Pub. Util. Code ss. 854)
provides that:

(a) No person or corporation, whether or not organized under the laws
of this state, shall merge, acquire, or control either directly or
indirectly any public utility organized and doing business in this
state without first securing authorization to do so from the
commission.

Section 854 does not apply to the Transaction because (1) SPPCo is not
a party to the transaction, (2) although SPPCo is a public utility, it is not
organized in California, and (3) even if SPPCo were organized in California, no
person or corporation is merging with, acquiring, or assuming control of SPPCo,
which is now and will continue after the Transaction to be a wholly owned
subsidiary of SPR, a publicly traded company in which no person or corporation
has or controls now more than 5% of the Company's stock, or after the merger,
will own or control more than the largest beneficial owner of shares owned or
controlled before the merger (i.e., less than 5%).

Although the CPUC does not have jurisdiction to review the Transaction
under ss. 854, under Cal. Pub. Util. Code ss. 853(a), the CPUC may possess
general jurisdiction to review merger transactions involving California public
utilities in cases where it affirmatively finds that asserting jurisdiction is
necessary to protect the public interest. The CPUC's jurisdiction under ss. 853
relating to mergers not covered by ss. 854 is not triggered unless and until the
CPUC affirmatively declares that it is necessary in the public interest that it
assert jurisdiction. In theory, even though the CPUC has no jurisdiction over
the Transaction under ss. 854, it conceivably could assert jurisdiction under
ss. 853 if the CPUC were to initiate a proceeding and make an affirmative
finding that application of ss. 854 to the Transaction with respect to SPPCo is
required "in the public interest." However, the CPUC has not attempted to
exercise any such jurisdiction and has indicated that it will not because its
interest in the matter will be addressed in the plant divestiture application.
Also, the CPUC has intervened in the Federal Energy Regulatory Commission's
("FERC") proceeding addressing the Transaction and has not opposed the
Transaction.

The Company met with senior CPUC Commission officers and staff in June
1998 and outlined the proposed Transaction. The Company also met with Staff
Counsel for the CPUC and the Chief of its Energy Regulatory Division on January
22,1999, to outline the scope of the proposed application to sell its generating
<PAGE>
Securities and Exchange Commission
February 10
Page 3

plants under Cal. Pub. Util. Code ss. 851, and met again with senior Commission
officials and the General Counsel of the Commission on January 28,1999, to
discuss the status of the merger and to outline the scope and timing of the
proposed ss. 851 application. Based on those meetings, SPPCo will file an
application to divest its generating plants in February 1999, with a view to
final sale to occur in late 1999 or 2000. Consequently, based on SPPCo's
divestiture filing and meetings with the CPUC, the CPUC has not and should not
assert jurisdiction over the Transaction pursuant to the plenary authority
granted under ss. 853(a).

Sincerely,

/s/ William E. Peterson
------------------------

WEP:jan

<PAGE>
EXHIBIT I-1

UNITED STATES OF AMERICA
before the
SECURITIES AND EXCHANGE COMMISSION

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
Release No. / , 1999

- -----------------------------------
)
In the Matter of )
)
Sierra Pacific Resources )
6100 Neil Road )
Reno, Nevada, 89511 )
)
Nevada Power Company )
6226 West Sahara Avenue )
Las Vegas, Nevada 89146 )
)
(70- ) )
- -----------------------------------)

Sierra Pacific Resources ("Sierra Pacific"), an intrastate holding
company exempt from registration requirements of the Public Utility Holding
Company Act of 1935 (the "Act") under section 3(a)(1) of the Act, and Nevada
Power Company ("Nevada Power") (collectively, "Applicants") have filed an
application-declaration on Form U-1 under Sections 9(a)(2) and 10 of the Act.
The Applicants request approval of a merger between Sierra Pacific and Nevada
Power, with Nevada Power to become a wholly-owned subsidiary of Sierra Pacific
(the "Transaction"). The Applicants also request an order under Section 3(a)(1)
of the Act declaring Sierra Pacific exempt from all provisions of the Act except
Section 9(a)(2) following consummation of the Transaction.

The Transaction will be governed by the terms of an Agreement and Plan
of Merger dated as of April 29, 1998 (the "Merger Agreement"), by and among
Nevada Power, Sierra Pacific, Desert Merger Sub, Inc. ("Desert Merger Sub"), and
Lake Merger Sub, Inc. ("Lake Merger Sub"). Sierra Pacific will create two
wholly-owned, special purpose subsidiary corporations named Desert Merger
<PAGE>
Sub and Lake Merger Sub, both to be Nevada corporations. Under the terms of the
Merger Agreement, first, Lake Merger Sub will be merged into Sierra Pacific,
with Sierra Pacific as the surviving corporation. Immediately thereafter, Nevada
Power will be merged into Desert Merger Sub. Desert Merger Sub, which will be
the surviving corporation, will then immediately change its name to Nevada Power
Company. It is through this second step that Nevada Power will become a
subsidiary of Sierra Pacific.

Nevada Power is an electric utility company under the Act. Sierra
Pacific owns all of the common stock of Sierra Pacific Power Company ("SPPC"),
which also is an electric and gas utility company under the Act. The Transaction
will not impact SPPC's structure; SPPC will continue to be a wholly-owned
subsidiary of Sierra Pacific, and will become a sister company to Nevada Power.
The Application states that the Transaction is designed to create a merged
company that will be able to participate more effectively in the increasingly
competitive energy marketplace.

Sierra Pacific is a public utility holding company incorporated in the
State of Nevada, which is exempt from regulation by the Commission under the Act
(except for Section 9(a)(2) thereof) pursuant to Section 3(a)(1) of the Act and
by order of the Commission. Sierra Pacific is headquartered in Reno, Nevada,
with operating subsidiaries primarily engaged in the energy and utility
businesses. SPPC, the principal subsidiary of Sierra Pacific, is a public
utility incorporated in the State of Nevada. SPPC provides electric service to
approximately 287,000 retail customers in northern Nevada and northeastern
California. SPPC also sells electric power at wholesale. In the Reno/Sparks area
of Nevada, SPPC distributes natural gas at retail to approximately 101,000
customers and provides water service to about 65,000 customers. During 1997, 92%
of SPPC's revenues were from retail sales of electricity, natural gas and water
in Nevada, 6% from retail sales of electricity in California and 2% from
wholesale sales of electricity in Nevada and California. SPPC's 1997 operating
revenues, which totaled $657.5 million, were comprised of its electric business
($540 million, or 82%), natural gas business ($70.7 million, or 11%) and water
business ($46.5 million, or 7%). As of December 31, 1997, SPPC's net utility
plant in service was $ 1.4 billion.

Sierra Pacific is engaged in non-utility businesses, as well as
certain other utility businesses that are not jurisdictional under the Act,
through a number of other subsidiaries, including investment in a natural gas
pipeline to serve an expanding gas market in Reno, northern Nevada and

2
<PAGE>
northeastern California, providing energy-related products and services both
inside and outside SPPC's service territory, managing non-utility property in
Nevada and California, and developing a customer information system for the
energy industry. For the year ended December 31, 1997, Sierra Pacific's
operating revenues on a consolidated basis were approximately $663 million, of
which $6 million are attributable to non-utility activities. Consolidated assets
of Sierra Pacific and its subsidiaries at December 31, 1997, were approximately
$1.9 billion, of which approximately $1.4 billion consisted of net utility plant
and equipment.

Nevada Power is a public utility, incorporated in the State of Nevada,
that provides retail electric service predominantly to the more than 1.3 million
residents of Clark County, Nevada, with limited service provided to the Federal
Department of Energy (U.S. Government Test Site) in Nye County, Nevada. Nevada
Power also sells electric power at wholesale. For the year ended December 31,
1997, Nevada Power's utility operating revenues on a consolidated basis were
approximately $799 million. Consolidated assets of Nevada Power and its
subsidiaries at December 31, 1997, were approximately $2.3 billion, of which
approximately $1.7 billion consisted of net electric plant and equipment. Nevada
Power does not have any material revenue generating subsidiaries.

The Merger Agreement provides for a two-step merger in which Nevada
Power will become a subsidiary of Sierra Pacific. The purpose of this two-step
process is to allow Nevada Power to become a first-tier subsidiary of Sierra
Pacific without generating any adverse tax consequences for any of the parties.
At the conclusion of the process, current Sierra Pacific and Nevada Power
shareholders will become Sierra Pacific shareholders. In the first step, Lake
Merger Sub will merge with and into Sierra Pacific, with Sierra Pacific
continuing as the surviving corporation. This step is necessary because, as
discussed below, each share of pre-merger Sierra Pacific common stock may be
exchanged for $37.55 in cash or 1.44 shares of Sierra Pacific common stock. The
exchange of pre-merger stock for cash or stock occurs as a result and at the
time of this first merger. The second step of the process commences immediately
after this first step. Nevada Power will merge with and into Desert Merger Sub.
Desert Merger Sub, which will be the surviving corporation, will then
immediately change its name to Nevada Power Company. It is through this second
step that Nevada Power will become a subsidiary of Sierra Pacific.

Under the Merger Agreement, each share of Sierra Pacific and Nevada
Power Common Stock will be converted into the right to receive cash and/or

3
<PAGE>
Sierra Pacific Common Stock. Each owner of Sierra Pacific Common Stock prior to
the first merger will be entitled to receive either 1.44 shares of Sierra
Pacific Common Stock or $37.55 in cash in exchange for each share of Sierra
Pacific Common Stock that it owns. Each owner of Nevada Power Common Stock prior
to the second merger will be entitled to receive either 1 share of Sierra
Pacific Common Stock or $26.00 in cash in exchange for each share of Nevada
Power stock that it owns. The cash consideration for Sierra Pacific and Nevada
Power stock represents a 5% premium per share of Sierra Pacific Common Stock or
Nevada Power Common Stock, respectively based on the 10-day average share price
of each company's stock prior to the Boards' approval of the Merger Agreement on
April 29, 1998. The total amount of cash to be paid to shareholders of
pre-merger Sierra Pacific Common Stock in the first merger is $151.6 million,
and the total amount to be paid to shareholders of Nevada Power Common Stock in
the second merger is $304.6 million. The Merger Agreement provides for
contingencies should shareholders elect to convert more or less than this amount
of their shares to cash. The Merger Agreement also provides for special
treatment of shareholders of less than 100 shares. Sierra Pacific will finance
the approximately $460 million necessary to fund the cash consideration provided
for under the Merger Agreement. The exact sources and precise methods of
financing this amount have not yet been determined. The Merger Agreement
provides that all outstanding shares of Nevada Power preferred stock will be
redeemed or otherwise retired prior to the consummation of the Transaction. At
any time upon 30 days notice to the holders of the Nevada Power preferred stock,
such stock is redeemable at a price of $21.00 per share for the 5.20% and 5.40%
series and at $20.25 per share for the 4.70% series. Nevada Power has not
determined precisely when or how it will retire the Nevada Power preferred
stock.

The Transaction is subject to certain closing conditions, including
governmental authorizations, consents, orders or approvals. The Nevada Power
Board of Directors and the Sierra Pacific Board of Directors approved the
Transaction on April 29, 1998. A majority of both the Nevada Power and Sierra
Pacific common shareholders voted in favor of the Transaction in separate
meetings held on October 9, 1998. A registration statement on Form S-4, which
includes a Prospectus was filed with the Commission on September 4, 1998. The
Transaction is conditioned, among other things, upon approval by the Securities
and Exchange Commission, the Public Utilities Commission of Nevada and the
Federal Energy Regulatory Commission, and on the expiration or termination of
the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements

4
<PAGE>
Act of 1976 (as amended) ("HSR Act"). The Applicants expect to make the HSR Act
filing in the first quarter of 1999.

The Applicants state that the Transaction will tend towards the
economical and efficient development of an integrated public-utility system and
that state laws have been complied with. Further, the Applicants state that the
Transaction will not result in an undue concentration of control or other harm
to the public interest or to the interests of investors or consumers.
Accordingly, the Applicants submit that the Transaction meets all requirements
of Section 10.

The Applicants also state that following the Transaction, the Sierra
Pacific holding company system will meet the statutory requirements of the
3(a)(1) exemption because it and each of its public utility subsidiaries from
which it derives a material part of its income will be predominantly intrastate
in character and will carry on their utility businesses substantially within the
State of Nevada.

The Application or Declaration and any amendments thereto are
available for public inspection through the Commission's Office of Public
Reference. Interested persons wishing to comment or request a hearing should
submit their views in writing by March 19, 1999, to the Secretary, Securities
and Exchange Commission, Washington, D.C. 20549, and serve a copy on the
Applicants at the addresses specified above. Proof of service (by affidavit or,
in the case of any attorney at law, by certificate) should be filed with the
request. Any request for a hearing shall identify specifically the issues of
fact or law that are disputed. A person who so requests will be notified of any
hearing, if ordered, and will receive a copy of any notice or order issued in
this matter. After March 19, 1999, the Application or Declaration, as filed or
as it may be amended, may be permitted to become effective.

For the Commission, by the Division of Investment Management, pursuant
to delegated authority.

Jonathan G. Katz
Secretary